10-Q

UNITED STATES

 SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware	20-0467835
(State or other jurisdictions of incorporation or organization)	(I.R.S. Employer Identification No.)
5320 Legacy Drive Plano, TX	75024
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (972) 673-2000

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes þ     No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes þ    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at November 1, 2011
Common Stock, $.001 par value	391,624,449

DENBURY RESOURCES INC.

INDEX

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010		3
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Nine Months Ended September 30, 2011 and 2010		6
Notes to Unaudited Condensed Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3. Quantitative and Qualitative Disclosures about Market Risk		31
Item 4. Controls and Procedures		32
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		33
Item 1A. Risk Factors		33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33
Item 6. Exhibits		33
Signatures		34

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except par value and share data)

	September 30,				December 31,
	2011				2010
ASSETS
Current assets
Cash and cash equivalents		$	24,363			$	381,869
Accrued production receivable			264,999				223,584
Trade and other receivables, net of allowance of $274 and $456, respectively			176,734				114,149
Short-term investments			81,851				93,020
Derivative assets			116,761				24,242
Deferred tax assets			-				27,454
Total current assets			664,708				864,318
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved			6,763,404				6,042,442
Unevaluated			1,088,733				870,130
CO2 and other non-hydrocarbon gases properties			599,881				523,423
Pipelines and plants			1,598,098				1,378,239
Other property and equipment			142,243				120,641
Less accumulated depletion, depreciation, amortization, and impairment			(2,510,715	)			(2,197,517	)
Net property and equipment			7,681,644				6,737,358
Derivative assets			56,460				12,919
Goodwill			1,236,094				1,232,418
Other assets			248,027				218,050
Total assets		$	9,886,933			$	9,065,063
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities		$	405,243			$	350,068
Oil and gas production payable			183,521				143,145
Derivative liabilities			9,253				78,184
Current maturities of long-term debt			8,177				7,948
Deferred taxes			37,326				-
Total current liabilities			643,520				579,345
Long-term liabilities
Long-term debt, net of current portion			2,396,549				2,416,208
Asset retirement obligations			87,725				81,290
Derivative liabilities			732				29,687
Deferred taxes			1,799,793				1,547,992
Other liabilities			22,842				29,834
Total long-term liabilities			4,307,641				4,105,011
Commitments and contingencies (Note 7)
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding			-				-
Common stock, $.001 par value, 600,000,000 shares authorized; 402,625,687 and 400,291,033 shares issued, respectively			403				400
Paid-in capital in excess of par			3,085,862				3,045,937
Retained earnings			1,856,868				1,336,142
Accumulated other comprehensive loss			(7,361	)			(488	)
Treasury stock, at cost, 0 and 78,524 shares, respectively			-				(1,284	)
Total stockholders' equity			4,935,772				4,380,707
Total liabilities and stockholders' equity		$	9,886,933			$	9,065,063

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Revenues and other income
Oil, natural gas, and related product sales	$	565,523		$	460,785		$	1,662,814		$	1,279,699
CO2 sales and transportation fees		6,541			4,653			16,808			13,840
Gain on sale of interests in Genesis		-			(3	)		-			101,537
Interest income and other income		4,441			1,268			12,445			7,658
Total revenues and other income		576,505			466,703			1,692,067			1,402,734
Expenses
Lease operating expenses		136,531			131,768			393,560			355,731
Production taxes and marketing expenses		36,949			35,542			109,388			92,959
CO2 discovery and operating expenses		1,358			2,488			5,381			5,537
General and administrative		28,906			37,115			103,652			101,016
Interest, net of amounts capitalized of $17,853, $10,917, $42,004 and $56,079, respectively		37,617			53,331			128,643			123,230
Depletion, depreciation, and amortization		101,978			111,602			299,067			322,683
Derivatives expense (income)		(210,154	)		31,854			(212,308	)		(138,045	)
Loss on early extinguishment of debt		-			-			16,131			-
Transaction and other costs related to the Encore Merger		-			11,470			4,377			79,253
Total expenses		133,185			415,170			847,891			942,364
Income before income taxes		443,320			51,533			844,176			460,370
Income tax provision (benefit)
Current income taxes		(5,331	)		3,704			5,849			11,314
Deferred income taxes		172,981			16,595			317,601			167,289
Consolidated net income		275,670			31,234			520,726			281,767
Less: net income attributable to noncontrolling interest		-			(2,130	)		-			(20,408	)
Net income attributable to Denbury stockholders	$	275,670		$	29,104		$	520,726		$	261,359
Net income per common share
Basic	$	0.69		$	0.07		$	1.31		$	0.72
Diluted	$	0.68		$	0.07		$	1.29		$	0.71
Weighted average common shares outstanding
Basic		399,040			395,913			398,371			362,241
Diluted		403,311			401,093			403,575			367,434

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities
Consolidated net income	$	520,726		$	281,767
Adjustments needed to reconcile to net cash provided by operating activities
Depletion, depreciation, and amortization		299,067			322,683
Deferred income taxes		317,601			167,289
Gain on sale of interests in Genesis		-			(101,537	)
Stock-based compensation		27,520			27,326
Non-cash fair value derivative adjustments		(217,092	)		(185,009	)
Loss on early extinguishment of debt		16,131			-
Other, net		9,024			14,254
Changes in operating assets and liabilities
Accrued production receivable		(45,017	)		48,453
Trade and other receivables		(53,012	)		20,548
Other assets		2,818			1,106
Accounts payable and accrued liabilities		(65,407	)		8,257
Oil and natural gas production payable		40,819			10,553
Other liabilities		(14,086	)		(22,915	)
Net cash provided by operating activities		839,092			592,775
Cash flows used for investing activities
Oil and natural gas capital expenditures		(741,256	)		(500,062	)
Acquisitions of oil and natural gas properties		(34,291	)		(24,390	)
Cash paid in Encore Merger, net of cash acquired		-			(813,894	)
Cash paid in Riley Ridge acquisition		(199,233	)		-
CO2 and other non-hydrocarbon gases capital expenditures		(65,866	)		(67,328	)
Pipelines and plants capital expenditures		(142,406	)		(169,157	)
Net proceeds from sales of oil and natural gas properties		47,598			909,986
Net proceeds from sale of interests in Genesis		-			162,619
Other		(22,798	)		(17,927	)
Net cash used for investing activities		(1,158,252	)		(520,153	)
Cash flows from financing activities
Bank repayments		(255,000	)		(1,519,000	)
Bank borrowings		365,000			1,229,000
Repayment of senior subordinated notes		(525,000	)		(609,424	)
Premium paid on repayment of senior subordinated notes		(13,137	)		(7,213	)
Net proceeds from issuance of senior subordinated notes		400,000			1,000,000
Net proceeds from issuance of common stock		12,348			8,614
Costs of debt financing		(13,104	)		(76,232	)
ENP distributions to noncontrolling interest		-			(24,513	)
Other		(9,453	)		(8,100	)
Net cash used for financing activities		(38,346	)		(6,868	)
Net increase (decrease) in cash and cash equivalents		(357,506	)		65,754
Cash and cash equivalents at beginning of period		381,869			20,591
Cash and cash equivalents at end of period	$	24,363		$	86,345

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Consolidated net income	$	275,670		$	31,234		$	520,726		$	281,767
Other comprehensive income, net of income tax
Net unrealized loss on available-for-sale securities, net of tax benefit of $2,420 and $4,244, respectively		(3,949	)		-			(6,925	)		-
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $11, $32, and $32, respectively		17			17			52			52
Change in deferred hedge loss on interest rate swaps, net of tax benefit of $14 and $32, respectively		-			(68	)		-			(155	)
Consolidated comprehensive income		271,738			31,183			513,853			281,664
Less: comprehensive income attributable to noncontrolling interest		-			(2,074	)		-			(20,308	)
Comprehensive income attributable to Denbury stockholders	$	271,738		$	29,109		$	513,853		$	261,356

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

We are a growing independent oil and natural gas company.  We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) 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, 2010.  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2011, our consolidated results of operations for the three and nine months ended September 30, 2011 and 2010, and our consolidated cash flows for the nine months ended September 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Noncontrolling Interest

From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP’s general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2010.  As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010, “Net income attributable to noncontrolling interest” of $2.1 million and $20.4 million, respectively, represents ENP’s results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to our stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share is calculated in the same manner, but also considers the impact of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and nine months ended September 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share.  The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the periods indicated:

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands	2011		2010		2011		2010
Basic weighted average common shares		399,040		395,913		398,371		362,241
Potentially dilutive securities:
Stock options and SARs		2,954		3,647		3,818		3,772
Performance equity awards		41		292		22		305
Restricted stock		1,276		1,241		1,364		1,116
Diluted weighted average common shares		403,311		401,093		403,575		367,434

Basic weighted average common shares excludes 3.4 million and 3.5 million shares for the three and nine months ended September 30, 2011, respectively,  and 3.4 million and 3.3 million shares for the three and nine months ended September 30, 2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant.  For purposes of calculating diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands	2011		2010		2011		2010
Stock options and SARs		4,731		4,270		3,108		4,613
Restricted stock		139		69		56		298

Short-term Investments

Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010.  The cost basis of this investment is $93.0 million.  We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations.  The unrealized loss on our short-term investment of $3.9 million (net of a tax benefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months ended September 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Recently Issued Accounting Pronouncements

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, Testing Goodwill for Impairment, (“ASU 2011-08”). ASU 2011-08 amends the FASC Intangibles – Goodwill and Other topic by permitting entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in the FASC Intangibles – Goodwill and Other topic.  We adopted ASU 2011-08 and will apply the guidance prospectively to interim and annual goodwill impairment tests.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend presentation requirements, it will not have a material effect on our consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Acquisitions and Divestitures

Acquisitions

October 2010 and August 2011 Acquisitions of Reserves in Rocky Mountain Region at Riley Ridge

In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase included a 42.5% interest in a gas plant, currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also included approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit.  The fair values assigned to assets acquired and liabilities assumed in the October 2010 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2010.

On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge not already owned, the remaining 57.5% interest in the gas plant and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $214.6 million after preliminary closing adjustments, including a $15 million deferred payment to be made at the time the property’s gas plant is operational and meets specific performance conditions. We expect the gas plant to be operational during the latter part of the first quarter of 2012.

Because the Riley Ridge plant is currently under construction, current production at the field is negligible.  As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011 and 2010.

The August 1, 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  The following table presents a summary of the fair value of the Riley Ridge assets acquired and liabilities assumed on August 1, 2011:

In thousands
Consideration:
Cash payment	$	199,554
Deferred payment(1)		15,000
Total consideration		214,554
Less:  Fair value of assets and liabilities acquired:(2)
Oil and natural gas properties
Proved		48,731
Unevaluated		12,542
CO2 and other non-hydrocarbon gases properties		9,741
Pipelines and plants		91,594
Other assets(3)		48,660
Asset retirement obligations		(389	)
		210,879
Goodwill	$	3,675
(1) The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property’s gas plant is operational and meets specific performance conditions as described above.
(2) Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments.
(3) Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned primarily by the Federal government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the future net revenues associated with the Company’s right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

2010 Merger with Encore Acquisition Company

On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.

For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $174.3 million and $435.2 million, respectively, of oil, natural gas sales and related product sales from properties acquired as part of the Encore Merger.  For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $114.1 million and $294.8 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) from properties acquired as part of the Encore Merger.  We recognized a total of $11.5 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended September 30, 2010, and $4.4 million and $79.3 million of such costs for the nine months ended September 30, 2011 and 2010, respectively.

Pro Forma Information

Had the Encore Merger occurred on January 1, 2010, our combined pro forma revenues and net income for the three and nine months ended September 30, 2010, would have been as follows:

	Pro Forma Results
In thousands, except per share amounts	Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
Pro forma total revenues	$	466,703	$	1,579,184
Pro forma net income attributable to Denbury stockholders		29,104		276,527
Pro forma net income per common share:
Basic	$	0.07	$	0.70
Diluted		0.07		0.69

Divestitures

2010 Sale of Interests in Genesis

In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (“Genesis”), for net proceeds of approximately $84 million.  In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.

2010 Sales of Non-Strategic Legacy Encore Properties

In May 2010, we sold certain non-strategic legacy Encore properties, primarily located in the Permian Basin, the Mid-continent area and the East Texas Basin (the “Southern Assets”), to Quantum Resources Management, LLC for consideration of $892.1 million after closing adjustments.  In August 2010, we sold additional legacy Encore properties, primarily located in the Cleveland Sand Play of western Oklahoma, for consideration of $32.1 million after closing adjustments.  We did not record a gain or loss on the sales in accordance with the full cost method of accounting.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Long-Term Debt

The following table shows the components of our long-term debt:

	September 30,			December 31,
In thousands	2011			2010
Bank Credit Agreement	$	110,000		$	-
7½% Senior Subordinated Notes due 2013, including discount of $437		-			224,563
7½% Senior Subordinated Notes due 2015, including premium of $427		-			300,427
9½% Senior Subordinated Notes due 2016, including premium of $12,538 and $14,589, respectively		237,458			239,509
9¾% Senior Subordinated Notes due 2016, including discount of $18,925 and $22,139, respectively		407,425			404,211
8¼% Senior Subordinated Notes due 2020		996,273			996,273
6⅜% Senior Subordinated Notes due 2021		400,000			-
Other Subordinated Notes, including premium of $35 and $41, respectively		3,841			3,848
NEJD Pipeline financing		164,626			167,331
Free State Pipeline financing		80,093			81,188
Capital lease obligations		5,010			6,806
Total		2,404,726			2,424,156
Less current obligations		(8,177	)		(7,948	)
Long-term debt and capital lease obligations	$	2,396,549		$	2,416,208

The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes.  DRI has no independent assets or operations.  Each of the subsidiary guarantors is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the subsidiary guarantors fully and unconditionally guarantee our senior subordinated debt jointly and severally.

Bank Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders as party thereto (the “Bank Credit Agreement”).  Availability under the Bank Credit Agreement is subject to a borrowing base which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations.  The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months.

In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Fifth Amendment”).  The Fifth Amendment extends the maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of debt to adjusted EBITDA.  Under the Fifth Amendment, the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base.  The Fifth Amendment also prescribes a commitment fee ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base, andadjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x.

In September 2011, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”).  The Sixth Amendment permits Denbury to make distributions to its equity holders, including specifically repurchase of its common stock and/or making cash dividends with respect thereto, in an aggregate amount of up to $500 million during the term of the Credit Facility, subject to certain restrictions, including pro forma availability of no less than 25% of the borrowing base at the time of any such transactions.  The Sixth Amendment provides us the flexibility to repurchase our common stock and/or pay cash dividends (within the $500 million limit) from time to time as deemed appropriate by, and subject to pre-approval of, our Board of Directors.  Also in September 2011, the banks reaffirmed our borrowing base of $1.6 billion under the Bank Credit Agreement until the next scheduled redetermination in May 2012.

6⅜% Senior Subordinated Notes due 2021

In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).

The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee this debt jointly and severally.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Redemption of our 2013 and 2015 Notes

On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 2013 Notes and all $300.0 million principal amount of our 2015 Notes. Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of par.  We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011.  We recognized a $16.1 million loss during the nine months ended September 30, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

Note 4.  Derivative Instruments

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts, and therefore the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the cash settlements of expired contracts are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production.  We do not hold or issue derivative financial instruments for trading purposes.  These contracts have consisted of price floors, collars and fixed price swaps.  The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices.  We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.

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. All of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands	2011			2010			2011			2010
Oil
Payment on settlements of derivative contracts	$	1,857		$	3,590		$	23,857		$	80,969
Fair value adjustments to derivative contracts - expense (income)		(205,355	)		62,450			(225,485	)		(144,471	)
Total derivative expense (income) - oil		(203,498	)		66,040			(201,628	)		(63,502	)
Natural Gas
Receipt on settlements of derivative contracts		(6,427	)		(13,626	)		(19,073	)		(34,005	)
Fair value adjustments to derivative contracts - expense (income)		(229	)		(19,933	)		8,393			(39,041	)
Total derivative expense (income) - natural gas		(6,656	)		(33,559	)		(10,680	)		(73,046	)
Ineffectiveness on interest rate swaps		-			(627	)		-			(1,497	)
Derivative expense (income)	$	(210,154	)	$	31,854		$	(212,308	)	$	(138,045	)

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables present outstanding commodity derivative contracts with respect to future production as of September 30, 2011:

				NYMEX Contract Prices Per Bbl
		Type of		Weighted Average Price
Year	Months	Contract	Bbls/d	Swap		Floor		Ceiling
Oil Contracts
2011	Oct - Dec	Swap	625	$	79.18	$	-	$	-
		Collar	45,500		-		70.33		101.74
		Put	6,625		-		69.53		-
	Total Oct - Dec 2011		52,750
2012	Jan - Mar	Swap	625		81.04		-		-
		Collar	52,000		-		70.00		106.86
		Put	625		-		65.00		-
	Total Jan - Mar 2012		53,250
	Apr-June	Swap	625		81.04		-		-
		Collar	53,000		-		70.00		119.44
		Put	625		-		65.00		-
	Total Apr - June 2012		54,250
	July-Sept	Swap	625		81.04		-		-
		Collar	53,000		-		80.00		128.57
		Put	625		-		65.00		-
	Total July - Sept 2012		54,250
	Oct - Dec	Swap	625		81.04		-		-
		Collar	53,000		-		80.00		128.57
		Put	625		-		65.00		-
	Total Oct - Dec 2012		54,250
2013	Jan - Mar	Collar	16,000		-		70.00		112.66
	Total Jan - Mar 2013		16,000

		Type of		Weighted Average Swap
Year	Months	Contract	MMBtu/d	Price per MMBtu
Natural Gas Contracts
2011	Oct - Dec	Swap	33,500	$	6.27
	Total Oct - Dec 2011		33,500
2012	Jan - Dec	Swap	20,000		6.53
	Total Jan - Dec 2012		20,000

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Additional Disclosures about Derivative Instruments

At September 30, 2011 and December 31, 2010, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

		Estimated Fair Value
		Asset (Liability)
In thousands		September 30,			December 31,
Type of Contract	Balance Sheet Location	2011			2010
Derivatives not designated as hedging instruments:
Derivative asset
Oil contracts	Derivative assets - current	$	96,177		$	3,050
Natural gas contracts	Derivative assets - current		20,584			21,192
Oil contracts	Derivative assets - long-term		52,627			1,301
Natural gas contracts	Derivative assets - long-term		3,833			11,618
Derivative liability
Oil contracts	Derivative liabilities - current		(60	)		(55,256	)
Deferred premiums	Derivative liabilities - current		(9,193	)		(22,928	)
Oil contracts	Derivative liabilities - long-term		(70	)		(25,906	)
Deferred premiums	Derivative liabilities - long-term		(662	)		(3,781	)
Total derivatives not designated as hedging instruments		$	163,236		$	(70,710	)

Note 5.  Fair Value Measurements

Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

• 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. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, 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. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.

• Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel).

We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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:
			Significant
	Quoted Prices		Other			Significant
	in Active		Observable			Unobservable
	Markets		Inputs			Inputs
In thousands	(Level 1)		(Level 2)			(Level 3)		Total
September 30, 2011
Assets
Short-term investments	$	81,851	$	-		$	-	$	81,851
Oil and natural gas derivative contracts		-		166,244			6,977		173,221
Liabilities
Oil and natural gas derivative contracts		-		(130	)		-		(130	)
Total	$	81,851	$	166,114		$	6,977	$	254,942
December 31, 2010
Assets
Short-term investments	$	93,020	$	-		$	-	$	93,020
Oil and natural gas derivative contracts		-		20,683			16,478		37,161
Liabilities
Oil and natural gas derivative contracts		-		(81,162	)		-		(81,162	)
Total	$	93,020	$	(60,479	)	$	16,478	$	49,019

The following table summarizes the changes in the fair value of our Level 3 assets for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
In thousands	2011				2010				2011				2010
Balance, beginning of period		$	6,638			$	40,283			$	16,478			$	-
Unrealized gains (losses) on commodity derivative contracts included in earnings			1,717				20,103				(5,359	)			35,002
Commodity derivative contracts acquired from Encore			-				-				-				38,093
Receipts on settlement of commodity derivative contracts			(1,378	)			(9,035	)			(4,142	)			(21,744	)
Balance, end of period		$	6,977			$	51,351			$	6,977			$	51,351

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

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements.  See Note 3, Long-Term Debt and Item 3, Quantitative and Qualitative Disclosures about Market Risk for further information about these financial instruments.

	September 30, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
In thousands	Amount		Fair Value		Amount		Fair Value
7½% Senior Subordinated Notes due 2013	$	-	$	-	$	224,563	$	228,375
7½% Senior Subordinated Notes due 2015		-		-		300,427		310,500
9½% Senior Subordinated Notes due 2016		237,458		242,914		239,509		249,661
9¾% Senior Subordinated Notes due 2016		407,425		460,458		404,211		475,380
8¼% Senior Subordinated Notes due 2020		996,273		1,046,087		996,273		1,080,956
6⅜% Senior Subordinated Notes due 2021		400,000		388,000		-		-

The fair values of our senior subordinated notes are based on quoted market prices.  We have other financial instruments consisting primarily of cash, cash equivalents, our Bank Credit Agreement, and short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 6.  Supplemental Information

Accounts Payable and Accrued Liabilities

The following table summarizes our accounts payable and accrued liabilities as of the periods indicated:

	September 30,		December 31,
In thousands	2011		2010
Accounts payable	$	107,391	$	47,660
Accrued exploration and development costs		143,647		101,758
Accrued compensation		27,476		39,757
Accrued lease operating expense		30,005		23,557
Accrued interest		28,957		57,077
Taxes payable		19,214		34,371
Deferred Riley Ridge acquisition consideration		15,000		-
Other		33,553		45,888
Total	$	405,243	$	350,068

Supplemental Cash Flow Information

The following table sets forth supplemental cash flow information for the periods indicated:

	Nine Months Ended
	September 30,
In thousands	2011		2010
Cash paid for interest, expensed	$	137,289		$	114,012
Cash paid for interest, capitalized		42,004			56,079
Cash paid for income taxes		36,688			13,691
Cash received for income tax refunds		21,990			13,525
Increase in liabilities for capital expenditures		86,769			13,880
Issuance of Denbury common stock in connection with the Encore Merger		-			2,085,681

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 7. Commitments and Contingencies

In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions.  The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions.  Under the three new contracts, Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC's Medicine Bow Fuel and Power LLC ("MBFP") project near Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("Mississippi Power") project in Mississippi, and purchase 100% of the CO2 captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas.  These new contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these new sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf.  We expect to begin taking delivery of approximately 100 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the Mississippi Power project by 2014, and 50 MMcf/d of CO2 from Air Products in late 2012.  Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price.  The purchase price of CO2 will fluctuate based on the changes in the price of oil. 

As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies.  The Mississippi Power and Air Products plants are currently being constructed, and the MBFP project is contingent upon securing debt financing, equity commitments and receipt of all necessary consents and approvals.

In conjunction with the August 1, 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third party purchaser.  Subsequently, we amended this contract to provide for annual delivery (to the 8/8ths working interest) of 127 MMcf of helium (previously 200 MMcf) during the first two years of the contract and thereafter provides for delivery of 400 MMcf of helium per year.  If the contracted quantity of helium is not supplied, we are obligated to compensate the third party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year.

In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. As a result of the prospective nature of the IRS’s determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are subject to review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.

We are subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe.  Currently, we have no material assessments for potential taxes.

 We are involved in various lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs.  We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Note 8. Subsequent Event

In early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company’s Board of Directors.  The program has no pre-established ending date, and may be suspended or discontinued at any time.  The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.  Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for $149.3 million, or $13.58 per share under this share repurchase program.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2010, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K.  Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K.  Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Information at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest CO2 reserves used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO2 tertiary recovery operations.

The acquisition of Encore Acquisition Company (the “Encore Merger”) on March 9, 2010, has had a significant impact on nearly every aspect of our business, including oil and natural gas production, revenues and operating expenses.  Accordingly, the Encore Merger impacts the comparability of our financial results from the first nine months of 2010 to those in the first nine months of 2011, which is more fully detailed throughout the following discussion and analysis.  Our financial results for the first nine months of 2010 include the results of operations of Encore from the date of the acquisition on March 9, 2010 through September 30, 2010.  Additionally, starting in May 2010 and throughout the remainder of 2010, we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).

Third Quarter Operating Highlights

We recognized net income of $275.7 million, or $0.69 per basic common share, during the third quarter of 2011 as compared to net income of $29.1 million, or $0.07 per basic common share, during the third quarter of 2010.  This increase between the two periods is primarily attributable to:

·   incremental income of $248.1 million ($153.8 million after tax) attributable to the non-cash increase in the fair value of the Company’s commodity derivative contracts, principally due to the change in NYMEX oil futures prices; and

·   an increase in revenue of $104.7 million ($64.9 million after tax), or 23%, as a result of higher commodity prices, partially offset by lower production as a result of asset sales in late 2010.

During the third quarter of 2011, our oil and natural gas production, which was 93% oil, averaged 66,830 BOE/d as compared to 77,730 BOE/d produced during the third quarter of 2010.  This drop in production is primarily attributable to the fourth quarter of 2010 sale of our Haynesville natural gas assets and our interests in ENP.  After adjusting third quarter 2010 production to exclude production from properties which were sold in the fourth quarter of 2010, continuing production in the third quarter of 2011 increased 6% over production in the comparable prior year quarter.  This production increase was primarily attributable to increases in our Bakken and tertiary oil production in the most recent quarter.  Our tertiary oil production averaged 31,091 Bbls/d during the third quarter of 2011, up 5% over the 29,531 Bbls/d produced during the third quarter a year earlier and up 1%, or 320 Bbls/d, over second quarter 2011 levels.  Our Bakken oil production averaged 9,976 BOE/d during the third quarter of 2011, an increase of 114% over production of 4,657 BOE/d during the third quarter of 2010 and sequentially up 2,350 BOE/d or 31% from levels in the second quarter of 2011.  See Results of Operations — CO2 Operations and Results of Operations — Operating Results — Production for more information.

Oil prices received during the third quarter of 2011 were considerably higher than prices received during the third quarter of 2010.  Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $91.98 per BOE during the third quarter of 2011, compared to $64.44 per BOE during the third quarter of 2010, a 43% increase between the comparative third quarter periods.  During the third quarter of 2011, our oil price differentials (our received net oil price compared to NYMEX West Texas Intermediate (“WTI”) prices) improved by $11.10 per Bbl, from a negative $3.85 per Bbl in the third quarter of 2010 to a positive $7.25 per Bbl in the third quarter of 2011, primarily due to the favorable price differential for our crude oil sold under Louisiana Light Sweet (“LLS”) index pricing.  See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information.

August 2011 Acquisition of Remaining Working Interest in Riley Ridge

On August 1, 2011, we acquired the remaining 57.5% working interest that we did not already own in the Riley Ridge Federal Unit (“Riley Ridge”), the remaining 57.5% interest in the gas plant and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge.  As a result of the transaction, we became the operator of both projects.  The purchase price after preliminary closing adjustments was approximately $214.6 million, which includes a $15 million deferred payment to be made at the time the property’s gas plant is operational and meets specific performance conditions.  We currently expect the gas plant to be operational with the first production of natural gas and helium from Riley Ridge during the latter part of the first quarter of 2012.  The CO2will be re-injected into the reservoir until we have completed an additional separation facility and a CO2pipeline to the field, which is expected to be completed in 2016.

Combining this acquisition with the interests in Riley Ridge that we acquired in October 2010, we estimate that, as of September 30, 2011, our total ownership at Riley Ridge contains estimated proved reserves of 431 Bcf of natural gas, 15.3 Bcf of helium and 2.2 Tcf of CO2.  The adjacent 28,000 acres is estimated to contain additional probable reserves of 250 to 300 Bcf of natural gas, 9.5 to 11.5 Bcf of helium and 2.0 to 2.2 Tcf of CO2, net to our interest.  These estimates of potential reserves, which include estimates of probable reserves based on the most recent drilling and technical data available, are more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering these reserves is subject to substantially greater risk.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Addition of Proved Oil and Natural Gas Reserves

We added 83.0 MMBOE of estimated proved reserves during the first nine months of 2011, including 52.1 MMBOE of estimated proved reserves during the third quarter of 2011.  The third quarter 2011 reserve additions include 237 Bcf  (39.5 MMBOE) in fields in the Riley Ridge acquisition completed in August, which is discussed above, 11.6 MMBOE in our Bakken properties, and minor revisions to our other properties.

Recent Common Share Repurchase Program

In early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company’s Board of Directors.  The program has no pre-established ending date, and may be suspended or discontinued at any time.  The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.  Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for $149.3 million, or $13.58 per share under this share repurchase program.

March 2011 CO2 Purchase Contracts

In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions.  The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions.  We will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC's Medicine Bow Fuel and Power LLC project ("MBFP") near Medicine Bow, Wyoming, 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("Mississippi Power") project in Mississippi, and 100% of the CO2captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas.  These three contracts each have an initial term of 15 to 16 years and include options to extend the term.  We estimate these three sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf.  We expect to begin taking delivery of approximately 100 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the Mississippi Power project in 2014, and 50 MMcf/d of CO2 from Air Products in late 2012.  Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price.  The purchase price of CO2 will fluctuate based on the changes in the price of oil.

As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies.  The Mississippi Power and Air Products plants are currently being constructed, and the MBFP project is contingent upon securing debt financing, equity commitments and receipt of all necessary consents and approvals.

February 2011 Senior Notes Refinancing

In February 2011, we issued, at par, $400 million of 6⅜% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to partially fund the repurchase of $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes in cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes.  In the first quarter of 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par and $220.9 million in principal of the 2015 Notes at 104.125% of par.  We redeemed the remaining outstanding 2015 Notes at 103.75% of par during the first quarter of 2011 and all of the remaining outstanding 2013 Notes at par on April 1, 2011.  During the nine months ended September 30, 2011, we recognized $16.1 million of loss associated with the debt repurchases, included in our income statements under the caption “Loss on early extinguishment of debt”.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Capital Resources and Liquidity

We currently project that our 2011 oil and gas capital investments will be $1.35 billion, excluding capitalized interest, tertiary start-up costs, acquisitions and divestitures, and net of equipment leases.

Our current 2011 capital budget includes the following:

·   $475 million allocated for tertiary oil field expenditures;

·   $400 million in the Bakken area of North Dakota;

·   $200 million to be spent on our CO2 pipelines;

·   $200 million to be spent on CO2 sources in the Jackson Dome and Riley Ridge areas; and

·   $75 million on drilling, completion and other development activities in our other areas.

During the first nine months of 2011, we have incurred expenditures of approximately $1 billion associated with our capital budget, net of equipment lease recoveries of $43 million.  Additionally, we have capitalized interest of $42.0 million and tertiary start-up costs related to Hastings and Oyster Bayou Fields of $23 million, which are not included in the above mentioned capital budget.  See additional detail on our expenditures below.

Based on oil and natural gas commodity futures prices in early November 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is expected to be $150 million to $250 million greater than our 2011 anticipated cash flow from operations.  This shortfall is expected to be funded with cash on hand (which was $381.9 million at December 31, 2010), and borrowings under our $1.6 billion bank credit facility.  Additionally, the future sale of our investment in Vanguard Natural Resources LLP units acquired in the sale of ENP, which have ranged in value between approximately $80 million and $95 million during the third quarter of 2011, could serve as another source of proceeds to fund our capital spending.  At October 31, 2011, we had drawn $350 million under our Bank Credit Facility, which was used in part to fund our August 1, 2011 Riley Ridge acquisition discussed above and in part to fund our share repurchase program discussed above.

As discussed above, in October 2011 we announced a common share repurchase program for up to $500 million of Denbury shares.  We plan to fund our share repurchase program in the near term through borrowings on our Bank Credit Facility and in the longer term by reducing our 2012 capital investments and/or by using proceeds from planned asset sales of miscellaneous minor properties.  As it is difficult to forecast future commodity prices, the number of shares repurchased and proceeds from asset sales, we may need to adjust our 2012 plans throughout the year as our goal is to keep any incremental debt related to these combined activities to approximately $250 million or less.   See details regarding our share repurchases above.

We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could impact the timing of our future production.  There are potential limitations on the amount of capital spending we can eliminate without penalties (refer to Management’s Discussion and Analysis – Capital Resources and Liquidity - Off-Balance Sheet Arrangements — Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010, and see CO2 Purchase Contracts above and Off-Balance Sheet Arrangements below for further information regarding additional commitments entered into during 2011).  In addition to the potential flexibility in our capital spending plans, as of October 31, 2011, we had approximately $1.25 billion of unused liquidity under our bank credit facility and have oil price floors through the first quarter of 2013 (see Note 4 to the Unaudited Condensed Consolidated Financial Statements), which together should provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly. 

Our capital spending estimate also assumes that we fund approximately $60 million of budgeted equipment purchases with operating leases, the amount of which is dependent upon securing acceptable financing.  Through September 30, 2011, we have funded approximately $43 million of these budgeted equipment purchases with operating leases.  Our net capital expenditures would increase by the amount of any shortfall in operating leases for this purchased equipment, and we anticipate funding any such additional capital expenditures under our Bank Credit Agreement.

In September 2011, we entered into our Sixth Amendment to the Bank Credit Agreement, enabling us to make certain distributions to our equity holders, including repurchase our common stock and/or make cash dividends on such common stock, in an aggregate amount of up to $500 million.  Also in September 2011, the banks reaffirmed our borrowing base of $1.6 billion under the Bank Credit Agreement.  See further discussion in Note 3 to the Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Capital Expenditure Summary

The following table of capital expenditures includes accrued capital for the nine months ended September 30, 2011 and 2010:

	Nine Months Ended
	September 30,
In thousands	2011		2010
Oil and natural gas exploration and development:
Drilling	$	399,812	$	242,302
Geological, geophysical, and acreage		26,609		23,381
Facilities		195,928		99,797
Recompletions		177,569		136,357
Capitalized interest		31,116		23,672
Total oil and natural gas exploration and development expenditures		831,034		525,509
CO2 and other non-hydrocarbon gases capital expenditures:
Drilling		47,750		29,222
Geological, geophysical, and acreage		9,314		17,341
Facilities		24,926		20,291
Total CO2 and other non-hydrocarbon gases capital expenditures		81,990		66,854
Pipelines and plants capital expenditures:
Pipelines and plants		114,024		138,511
Capitalized interest		10,888		32,407
Total pipelines and plants capital expenditures		124,912		170,918
Total capital expenditures excluding acquisitions		1,037,936		763,281
Oil and natural gas property acquisitions		34,291		24,390
Consideration for the Encore Merger(1)		-		2,952,515
Consideration for August 2011 Riley Ridge acquisition		214,554		-
Total	$	1,286,781	$	3,740,186

(1) Consideration given in the Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued.

Our capital expenditures, excluding the Riley Ridge acquisition, for the first nine months of 2011 were funded with $839.1 million of cash flow from operations, and cash on hand at the beginning of the period. Our capital expenditures for the first nine months of 2010, excluding the Encore Merger, were funded with $592.8 million of cash flow from operations together with proceeds from the sales of our interests in Genesis Energy, L.P. (“Genesis”) and non-strategic legacy Encore properties sold during May 2010 (the “Southern Assets”).

Off-Balance Sheet Arrangements

Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry.  In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in our proved reserve reports.  Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements.

In April 2011, we entered into three long-term drilling contracts.  Our total commitment under these contracts is approximately $91 million, with $7 million expected to be paid during the remainder of 2011, $31 million in both 2012 and 2013, and $22 million in 2014.

In May 2011, we entered into an agreement with Elk Petroleum to acquire a 65% working interest in Grieve Field, a planned CO2 enhanced oil recovery project located in Wyoming.  Denbury will invest the first $28.5 million of capital and operating costs in Phase 1.  In Phase 2 of the project, Denbury may fund, at Elk’s option, Elk’s 35% share of the next $34.3 million of capital and operating costs, with Denbury recouping its Phase 2 expenditures (plus interest) out of Elk’s 35% working interest share of production from the project.  In connection with that agreement, we were assigned a CO2 purchase and CO2 transportation contract to purchase CO2 reserves from Exxon Mobil Corporation’s La Barge facility and transport the CO2 to Grieve Field beginning in March of 2012.  Our annual commitment under the CO2 purchase and transportation contracts is approximately $16 million annually for 2 years and approximately $25 million annually for the remaining 8 years (assuming a $100 per barrel NYMEX oil price).      

Our commitments and obligations consist of those detailed as of December 31, 2010 in our2010Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations - Off-Balance Sheet Arrangements – Commitments and Obligations, plus the long-term drilling contracts described above, the Grieve Field obligations detailed above, and the three CO2 purchase contracts entered into during the first quarter of 2011, which CO2 purchase contracts are subject to numerous contingencies, as discussed under Overview – CO2 Purchase Contracts above.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

CO2 Operations

Our focus on CO2 operations is the primary strategy of our business and operations.  We believe that there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this potential in our Annual Report on Form 10-K for the year ended December 31, 2010 and other public disclosures.  In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results.  Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the section entitled CO2 Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding these matters.

During the third quarter of 2011, our CO2 production at Jackson Dome averaged 1,001 MMcf/d, compared to an average of 864 MMcf/d produced during the third quarter of 2010 and 992 MMcf/d produced during the second quarter of 2011.  We used 90% of this production, or 903 MMcf/d, in our tertiary operations during the third quarter of 2011, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.  Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Off-Balance Sheet Arrangements – Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion on our CO2 delivery obligations.  We recognized a negative proven CO2 reserve revision during the second quarter of approximately 239 Bcf at our Jackson Dome Dri-Dock prospect.  This revision was a result of the second well in this formation not being a productive well and analysis of the reprocessed seismic data, which showed incremental faulting in the Dri-Dock reservoir.  During October, 2011, we completed another well in the Gluckstadt prospect.  We estimate that this well added approximately 313 Bcf of additional proven CO2 reserves.  After adjusting for these changes, we believe that we have sufficient CO2 reserves to develop our current Gulf Coast enhanced oil recovery program and we are continuing to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome.  At December 31, 2010, our proven CO2 reserves at Jackson Dome were approximately 7.1 Tcf.

During the fourth quarter of 2011 we commenced drilling an exploratory well at Jackson Dome.  Because we have not established proved or probable reserves in the drilling area, in accordance with our accounting policy for CO2 properties, we expect to expense between $9 million and $12 million of drilling costs during the fourth quarter of 2011, which will be classified as “CO2 discovery and operating expenses” on our Statement of Operations.

We spent approximately $0.26 per Mcf in operating expenses to produce our CO2 during the first nine months of 2011, which costs averaged $0.25 per Mcf during the first quarter of 2011, $0.28 per Mcf during the second quarter of 2011, and $0.24 per Mcf during the third quarter of 2011.  This rate is up significantly from our $0.21 per Mcf cost during the third quarter of 2010, due primarily to increased CO2 royalty expense as a result of higher oil prices (to which CO2 royalties are tied).

The following table summarizes our tertiary oil production and tertiary lease operating expense per Bbl for each quarter in 2010 and the first, second, and third quarters of 2011:

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Average Daily Production (Bbls/d)
	First		Second		Third		Fourth		First		Second		Third
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2010		2010		2010		2010		2011		2011		2011
Phase 1:
Brookhaven		3,416		3,277		3,323		3,699		3,664		3,213		3,030
McComb area		2,289		2,160		2,484		2,433		2,161		1,983		2,005
Mallalieu area		3,443		3,628		3,279		3,164		2,925		2,646		2,620
Other		2,817		3,282		3,343		3,361		3,290		3,196		2,879
Phase 2:
Heidelberg		1,708		1,857		2,806		3,422		3,374		3,548		3,141
Eucutta		3,792		3,625		3,284		3,286		3,247		3,114		2,985
Soso		3,213		3,207		3,016		2,828		2,582		2,317		2,331
Martinville		927		764		606		586		500		416		453
Phase 3:
Tinsley		4,419		5,248		6,024		6,614		6,567		6,990		7,075
Phase 4:
Cranfield		936		811		855		1,043		991		1,085		1,214
Phase 5:
Delhi		63		648		511		703		1,524		2,263		3,358
Total tertiary oil production		27,023		28,507		29,531		31,139		30,825		30,771		31,091
Tertiary operating expense per Bbl	$	22.67	$	21.37	$	22.54	$	22.26	$	25.40	$	23.35	$	25.34

Oil production from our tertiary operations increased to an average of 31,091 Bbls/d during the third quarter of 2011, a 5% increase over our third quarter of 2010 tertiary production level, primarily due to production growth in response to continued expansion of the tertiary floods in the Delhi, Tinsley, Cranfield, and Heidelberg Fields.  The initial tertiary production response at Delhi Field occurred late in the first quarter of 2010, and production there has subsequently increased steadily as we have expanded the CO2 flood.  Offsetting these production gains were declines in our more mature Phase 1 and Phase 2 fields (excluding Heidelberg).

The production growth rate at a tertiary flood can vary from quarter to quarter as a tertiary field’s production may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume its growth as additional areas of the field are developed.  During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production.  We also find it difficult to precisely predict when any given well will respond to the injected CO2, as the CO2 seldom travels through the rock consistently due to heterogeneity in the oil-bearing formations.  We find all of these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the entire field is developed, albeit sometimes in inconsistent patterns.  These types of fluctuations were most noticeable at Tinsley and Heidelberg Fields during the first three quarters of 2011, two of our fields which have exhibited strong production growth in the recent past.  During the third quarter of 2011, we shut-in our Heidelberg Field for seven days for compressor maintenance and repairs to the main facility, which we estimate lowered third quarter tertiary production from the field by approximately 250 Bbls/d.  In addition, at Heidelberg Field we experienced rapid production growth in late 2010 as the CO2 moved rapidly through the more permeable zones.  We are implementing a plan which will force the CO2 into the less permeable zones in order to recover the oil trapped in those intervals.  At Tinsley Field, we stopped CO2 injections in parts of the field in order to address issues with wells that were improperly plugged by prior operators.  These issues have slowed our previously anticipated production growth this year, and production growth will likely not resume until 2012.  These temporary fluctuations have not changed our overall expectations of recovery in the Heidelberg and Tinsley Fields.

We initiated CO2 injections at Oyster Bayou and Hastings Fields during June 2010 and December 2010, respectively. We currently anticipate initial tertiary production at Hastings around year-end 2011 and first tertiary production at Oyster Bayou Field late in the first quarter of 2012, assuming completion of CO2 recycle facilities.

We commenced construction of the first segment of our 232-mile, 20-inch Greencore CO2 pipeline in Wyoming during August 2011.  This 114-mile segment of the pipeline starts in Natrona County and runs through Johnson and southwestern Campbell Counties, Wyoming.  In late 2012 we plan to complete the compression station at Lost Cabin and complete the pipeline to Bell Creek Field in southeast Montana.

During the third quarter of 2011, operating costs for our tertiary properties averaged $25.34 per Bbl, up 12% from our third quarter 2010 average cost of $22.54 per Bbl, due primarily to higher workover, repair and equipment rental expenses in the most recent quarter, plus higher CO2 costs due to higher oil prices.  For the first nine months of 2011, operating costs for our tertiary properties averaged $24.70 per Bbl, an increase of 11% compared to such costs in the prior-year period, with such increase attributable to similar factors except that equipment rental was essentially flat and the increase in CO2 costs was more significant.  The increase in workover expenses for these periods is primarily due to maintenance and repairs at Heidelberg Field and workover costs at Tinsley Field as discussed above.  The increase in equipment rental expense in the third quarter comparison is due primarily to additional leasing on certain facility equipment in 2011.  For any specific field, we expect our tertiary lease operating expense per Bbl to be high initially and then decrease as production increases, ultimately leveling off until production begins to decline in the latter life of the field, when lease operating expense per barrel will again increase.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating Results

Certain of our operating results and statistics for the comparative third quarters and first nine months of 2011 and 2010 are included in the following table:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
In thousands, except per share and unit data	2011		2010(1)			2011			2010(1)
Operating results:
Net income attributable to Denbury stockholders	$	275,670	$	29,104		$	520,726		$	261,359
Net income per common share - basic		0.69		0.07			1.31			0.72
Net income per common share - diluted		0.68		0.07			1.29			0.71
Cash flow from operations		315,739		208,484			839,092			592,775
Average daily production volumes:
Bbls/d		61,984		64,233			60,007			58,234
Mcf/d		29,079		80,983			30,736			81,065
BOE/d		66,830		77,730			65,129			71,745
Operating revenues:
Oil sales	$	552,281	$	426,896		$	1,621,047		$	1,176,085
Natural gas sales		13,242		33,889			41,767			103,614
Total oil and natural gas sales	$	565,523	$	460,785		$	1,662,814		$	1,279,699
Commodity derivative contracts: (2)
Net cash receipts (payments) on settlement of commodity derivative contracts	$	4,570	$	10,036		$	(4,784	)	$	(46,964	)
Non-cash fair value derivative gains (losses)		205,584		(42,517	)		217,092			183,512
Total income (expense) from commodity derivative contracts	$	210,154	$	(32,481	)	$	212,308		$	136,548
Operating expenses:
Lease operating	$	136,531	$	131,768		$	393,560		$	355,731
Production taxes and marketing		36,949		35,542			109,388			92,959
Total production expenses	$	173,480	$	167,310		$	502,948		$	448,690
Unit prices - including impact of derivative settlements: (2)
Oil price per Bbl	$	96.52	$	71.63		$	97.50		$	68.88
Natural gas price per Mcf		7.35		6.38			7.25			6.22
Unit prices - excluding impact of derivative settlements: (2)
Oil price per Bbl	$	96.85	$	72.24		$	98.95		$	73.98
Natural gas price per Mcf		4.95		4.55			4.98			4.68
Oil and natural gas operating revenues and expenses per BOE:
Oil and natural gas revenues	$	91.98	$	64.44		$	93.52		$	65.34
Oil and natural gas lease operating expenses	$	22.21	$	18.43		$	22.13		$	18.16
Oil and natural gas production taxes and marketing expense		6.01		4.97			6.15			4.75
Total oil and natural gas production expenses	$	28.22	$	23.40		$	28.28		$	22.91
(1) Includes the results of operations of Encore properties and ENP from March 9, 2010 through September 30, 2010.
(2) See Item 3, Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Production

Average daily production by area for each of the four quarters of 2010 and for the first, second, and third quarters of 2011 are shown below:

	Average Daily Production (BOE/d)
	First Quarter		Pro Forma		Second Quarter		Third Quarter		Fourth Quarter		First Quarter		Second Quarter		Third Quarter
			First Quarter
Operating Area	2010(1)		2010(2)		2010		2010		2010		2011		2011		2011
Gulf Coast Region:
Tertiary oil fields		27,023		27,023		28,507		29,531		31,139		30,825		30,771		31,091
Non-tertiary fields:
Mississippi		7,829		7,829		8,967		7,965		7,293		7,586		7,333		7,193
Texas		5,235		5,235		5,148		4,824		4,564		4,371		4,202		4,096
Louisiana		662		662		775		714		687		767		659		214
Alabama and other		997		997		1,078		1,091		1,026		1,026		1,084		1,072
Total Gulf Coast Region		41,746		41,746		44,475		44,125		44,709		44,575		44,049		43,666
Rocky Mountain Region:
Cedar Creek Anticline		2,537		9,830		9,967		9,791		9,328		9,163		8,925		8,930
Bakken		890		3,549		4,500		4,657		5,193		5,728		7,626		9,976
Bell Creek		252		966		997		994		957		890		936		889
Paradox		173		675		702		738		716		635		690		680
Other		777		2,925		2,944		2,889		2,809		2,613		2,693		2,689
Total Rocky Mountain Region		4,629		17,945		19,110		19,069		19,003		19,029		20,870		23,164
Total Continuing Production		46,375		59,691		63,585		63,194		63,712		63,604		64,919		66,830
Disposed Properties:
Legacy Encore properties		4,479		17,853		11,684		5,906		4,156		-		-		-
ENP		2,271		9,034		8,842		8,630		8,567		-		-		-
Total Production		53,125		86,578		84,111		77,730		76,435		63,604		64,919		66,830
(1) Includes production of Encore and ENP from March 9, 2010 through March 31, 2010.
(2) Represents pro forma production assuming we had reported the production from the Encore Merger beginning January 1, 2010.

Continuing production during the three months ended September 30, 2011 increased 3,636 BOE/d over the comparable 2010 production levels, and continuing production when including Encore’s pre-merger production increased from 62,169 BOE/d during the first nine months of 2010 to 65,129 BOE/d during the first nine months of 2011.  These increases were primarily due to production increases from the Bakken and our tertiary oil fields (see a discussion of our tertiary operations in CO2 Operations above), offset by normal declines in most of our other non-tertiary properties.  Total production decreased 14% between the third quarters of 2010 and 2011 due to the sale of the Haynesville natural gas assets, as well as the sale of our interests in ENP, in the fourth quarter of 2010.  On a year-to-date basis, total production decreased 6,616 BOE/d between the first nine months of 2010 and 2011 due primarily to the sale of the non-strategic Encore assets, including the Haynesville and ENP interests, during 2010.  Our production from the Cedar Creek Anticline generally declines in periods of increasing prices due to a net profits interest associated with this production; therefore, a portion of the decline in 2011 production at this field is related to the increase in oil prices during 2011.

Production from our Bakken properties averaged 9,976 BOE/d in the third quarter of 2011, a 114% increase from third quarter 2010 levels and an increase of over 31% compared to second quarter 2011 production levels.  The production increases in the Bakken are due to an acceleration of our drilling activities in the area, as we have increased our operated drilling rigs from two at the time of the Encore acquisition in March 2010, to five rigs at the beginning of 2011, and seven operated rigs at the end of the third quarter of 2011.  During the first nine months of 2011, we drilled and completed 24 operated wells in the Bakken.  Our Bakken production growth for the first six months of 2011 was negatively impacted by severe winter weather and spring flooding, which caused delays in well completions and curtailments in oil production; however, with the increase in operated drilling rigs and good weather conditions we have caught up on the backlog of our wells requiring fracturing treatment.  A test well drilled in the Almond area in October 2011 indicated the reservoir was noncommercial at the current oil price.  Based on the results of the first test well, we determined a second Almond test was not necessary to evaluate the area.

Our production during the three and nine months ended September 30, 2011 was 93% and 92% oil, respectively, as compared to 83% and 81% oil during the three and nine months ended September 30, 2010, respectively.  This increase is due to the sales of the non-strategic Encore properties and ENP properties in 2010, which had a higher percentage of natural gas production, and increases in our tertiary and Bakken production, which are primarily oil.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Oil and Natural Gas Revenues. Although our production for the three and nine months ended September 30, 2011 declined from comparable 2010 levels due to the asset sales discussed above, our oil and natural gas revenues increased significantly in the current periods due to higher oil prices.  These changes in oil and natural gas revenues, excluding any impact of our commodity derivative contracts, are reflected in the following table:

	Three Months Ended September 30,			Nine Months Ended September 30,
	2011 vs. 2010			2011 vs. 2010
In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Increase in commodity prices	$	169,368	37%	$	501,114	39%
Decrease in production		(64,630)	(14%)		(117,999)	(9%)
Total increase in oil and natural gas revenues	$	104,738	23%	$	383,115	30%

Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first, second, and third quarters and the nine months ended September 30, 2011 and 2010:

	Three Months Ended						Three Months Ended					Three Months Ended					Nine Months Ended
	March 31,						June 30,					September 30,					September 30,
	2011			2010			2011		2010			2011		2010			2011		2010
Net Realized Prices:
Oil price per Bbl	$	93.67		$	76.53		$	106.30	$	73.99		$	96.85	$	72.24		$	98.95	$	73.98
Natural gas price per Mcf		4.81			5.40			5.16		4.44			4.95		4.55			4.98		4.68
Price per BOE		88.42			69.21			100.06		63.76			91.98		64.44			93.52		65.34
NYMEX Differentials:
Oil per Bbl	$	(0.59	)	$	(2.08	)	$	3.72	$	(4.13	)	$	7.25	$	(3.85	)	$	3.49	$	(3.62	)
Natural gas per Mcf		0.61			0.37			0.78		0.09			0.89		0.31			0.77		0.14

As reflected in the table above, our oil price differentials have continued to improve significantly, primarily due to the favorable price differential for crude oil sold under LLS index pricing.  Company-wide oil price differentials in the third quarter of 2011were $7.25 per Bbl above NYMEX, as compared to an average negative differential of $3.85 per Bbl below NYMEX in the third quarter of 2010, an increase of $11.10 per Bbl.  Our oil price differentials in the 2010 periods reflected production from the non-strategic Encore properties sold in 2010, which typically received lower oil prices than our legacy production.    During the latter part of the first quarter of 2011, the LLS index price increased significantly more than NYMEX prices, causing the LLS differential to increase significantly, and it has remained high and further increased throughout the second and third quarters.  For the third quarter of 2011, this LLS differential averaged a positive $18.90 per barrel on a trade-month basis, as compared to a $9.28 and $15.32 positive differential in the first and second quarters of 2011, respectively, and a more typical $3.11 positive differential in the third quarter of 2010.  It is uncertain how long this LLS differential will remain at this level.  Because our derivative contracts are based on NYMEX prices, they do not impact the differential we receive.  We currently sell approximately (a) 42% of our crude oil based on the LLS index price, although due to contract provisions we may not realize the full differential; (b) 38% based on WTI prices; and (c) 20% based on various other indexes, most of which have also improved relative to WTI, but to a lesser degree.

Commodity Derivative Contracts. The following tables summarize the impact our commodity derivative contracts had on our operating results for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,
	2011				2010				2011			2010			2011			2010
In thousands	Oil Derivative Contracts								Natural Gas Derivative Contracts						Total Commodity Derivative Contracts
Non-cash fair value gain (loss)		$	205,355			$	(62,450	)		$	229		$	19,933		$	205,584		$	(42,517	)
Cash settlement receipts (payments)			(1,857	)			(3,590	)			6,427			13,626			4,570			10,036
Total		$	203,498			$	(66,040	)		$	6,656		$	33,559		$	210,154		$	(32,481	)

	Nine Months Ended September 30,
	2011				2010				2011				2010			2011				2010
In thousands	Oil Derivative Contracts								Natural Gas Derivative Contracts							Total Commodity Derivative Contracts
Non-cash fair value gain (loss)		$	225,485				144,471				(8,393	)			39,041		$	217,092			$	183,512
Cash settlement receipts (payments)			(23,857	)			(80,969	)			19,073				34,005			(4,784	)			(46,964	)
Total		$	201,628			$	63,502			$	10,680			$	73,046		$	212,308			$	136,548

Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our commodity derivative contracts.  Because we do not utilize hedge accounting for our commodity derivative contracts, the changes in fair value of these contracts, as outlined above, are recognized currently in the income statement.  See Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Production Expenses. Our lease operating expenses increased 4% during the three months ended September 30, 2011 compared to the level of these expenses in the same period in 2010.  This increase is primarily attributable to an 18% increase in our tertiary operating expenses, from $61.3 million to $72.5 million, offset in part by a decrease in our non-tertiary lease operating expenses of $6.5 million, or 9%.  The increase in our tertiary operating expenses is due primarily to additional CO2 injection costs due to higher oil prices (to which CO2 prices are partially tied) and increased workover costs, which increases are further discussed above under CO2 Operations. The decrease in our non-tertiary operating costs is primarily due to the sale of Haynesville properties and ENP in the fourth quarter of 2010, which reduced our lease operating costs by $12.3 million, offset in part by increases in operating expenses in our Rocky Mountain region, primarily at Cedar Creek Anticline, where we experienced higher workover costs in the third quarter of 2011.

For the nine months ended September 30, 2011, our lease operating expenses increased by 11% over those in the 2010 nine month period.  This increase is also primarily attributable to a 21% increase in our tertiary operating expenses, from $171.8 million to $208.3 million.  Our non-tertiary lease operating expenses increased slightly over the prior year nine-month period (1%), as the savings of approximately $35.8 million due to the sale of legacy Encore assets in 2010 was offset by increased expenses in the Cedar Creek Anticline Field and other Rocky Mountain region properties, including our expansion of Bakken Field operations.

Lease operating expense averaged $22.21 per BOE and $22.13 per BOE for the three and nine months ended September 30, 2011, compared to $18.43 per BOE and $18.16 per BOE for the same periods in 2010.  These increases from the respective prior periods are attributable to the sale of the non-strategic Encore and ENP properties from May 2010 through December 2010, which were primarily natural gas properties that generally had a lower operating cost per BOE than Denbury’s legacy properties.  Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $25.34 per Bbl and $24.70 per Bbl during the three and nine months ended September 30, 2011, compared to $22.54 per Bbl and $22.19 per Bbl for the same periods in 2010.  See CO2 Operations for a more detailed discussion.

Generally, production taxes change in relation to oil and natural gas revenues, and marketing expenses change in relation to production volumes.  The 23% increase in oil and natural gas revenues between the third quarters of 2010 and 2011 contributed to severance taxes increasing from $26.2 million in 2010 to $30.5 million in 2011.  Likewise, the 30% increase in oil and natural gas revenues between the first nine months of 2010 and 2011 contributed to severance taxes increasing from $69.8 million in the first nine months of 2010 to $91.4 million in the first nine months of 2011.  These severance tax increases in both comparative periods were partially offset by lower marketing expenses primarily attributable to lower production volumes in 2011.

General and Administrative Expenses (“G&A”)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per BOE data and employees	2011			2010			2011			2010
Gross G&A expenses (excluding stock compensation)	$	57,061		$	61,532		$	184,895		$	167,715
Gross stock-based compensation		11,154			9,832			32,178			27,134
State franchise taxes		1,894			952			4,721			2,987
Operator labor and overhead recovery charges		(31,720	)		(30,633	)		(92,859	)		(81,764	)
Capitalized exploration and development costs		(9,483	)		(4,568	)		(25,283	)		(15,056	)
Net G&A expense	$	28,906		$	37,115		$	103,652		$	101,016
G&A per BOE:
Net G&A expense(1)	$	2.94		$	3.88		$	4.14		$	3.83
Net stock-based compensation(1)		1.45			1.18			1.42			1.18
State franchise taxes		0.31			0.13			0.27			0.15
Net G&A expense	$	4.70		$	5.19		$	5.83		$	5.16
Employees as of September 30		1,274			1,225			1,274			1,225
(1) Net of operator labor and overhead recovery charges, and capitalized exploration and development costs.

Gross G&A expenses decreased $4.5 million (7%) during the three months ended September 30, 2011, but increased $17.2 million (10%) during the nine months ended September 30, 2011, as compared to the same periods of 2010.  The decrease between the comparative third quarters was primarily caused by a reduction in third-party professional services and accrued bonus compensation, offset in part by higher salary and benefits costs and additional compensation related to the resignation of Tracy Evans from his officer's position as Denbury's President and Chief Operating Officer.  Gross stock-based compensation was also higher in the 2011 periods, due in part to the President and Chief Operating Officer's resignation of his officer's position.

The year-to-date comparative increase is primarily impacted by increased expense resulting from the Encore Merger, as the 2010 period includes the effect of the Encore Merger beginning on the acquisition date, March 9, 2010.  The number of employees at September 30, 2011 represents a 49% increase over our headcount prior to the Encore Merger, which was 856 employees.  Additional expense attributable to the legacy Encore office leases and the new Denbury headquarters lease, together with related moving costs, also contributed to the higher cash G&A expense during the first nine months of 2011.

Gross G&A expense during the three and nine months ended September 30, 2011 was offset in part by an increase in operator overhead recovery charges.  Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well.  As a result of additional operated wells and drilling activities, additional tertiary operations and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 4% and 14% during the three and nine months ended September 30, 2011, as compared to the same periods in 2010.  Capitalized exploration and development costs also increased between the periods, primarily due to increased compensation costs subject to capitalization.

The net effect of these changes resulted in a 22% decrease (a 9% decrease on a per BOE basis) in G&A expense between the comparable third quarters of 2011 and 2010, and a 3% increase (13% increase on a per BOE basis) between the comparable first nine months of 2011 and 2010.   Lower production attributable to the 2010 property sales was the primary factor relating to the higher cost per BOE in the 2011 nine-month period as compared to the 2010 nine-month period, as any cost savings as a result of the property sales were offset by other expenses, including compensation increases effective at the beginning of 2011 and incremental expense attributable to the legacy Encore office leases and the new Denbury headquarters noted above.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Interest and Financing Expenses
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
In thousands, except per BOE data and interest rates		2011				2010				2011				2010
Cash interest			$	51,540			$	58,234			$	156,255			$	164,173
Non-cash interest				3,930				6,014				14,392				15,136
Less: capitalized interest				(17,853	)			(10,917	)			(42,004	)			(56,079	)
	Interest expense, net		$	37,617			$	53,331			$	128,643			$	123,230
Interest income and other			$	4,441			$	1,268			$	12,445			$	7,658
Net cash interest expense and other income per BOE (1)			$	4.80			$	6.57			$	5.79			$	5.27
Average debt outstanding			$	2,426,820			$	2,751,258			$	2,415,193			$	2,710,573
Average interest rate (2)				8.5	%			8.5	%			8.6	%			8.1	%
(1) Cash interest expense less capitalized interest less interest income and other income on a per BOE basis.
(2) Includes commitment fees but excludes debt issue costs and amortization of discount and premium.

Cash interest expense decreased $6.7 million during the three month period ending September 30, 2011, as compared to the same period in 2010, primarily due to a decrease in our average debt outstanding.  Our debt level increased in early 2010 as a result of the Encore Merger and decreased throughout 2010 and in early 2011 as we repaid debt with proceeds from the sale of non-strategic legacy Encore assets and our ENP ownership interests.  As a result, our year-to-date cash interest expense was also lower than that incurred in the same period in 2010.  The 64% increase in capitalized interest between the third quarters of 2010 and 2011 relates primarily to incremental capitalized interest on CO2 floods, Riley Ridge and the Greencore Pipeline, offset in part by a reduction in capitalized interest on the Green Pipeline, a significant portion of which was placed into service in June 2010, with the remaining portion placed into service in December 2010.  Capitalized interest for the 2011 nine-month period is lower than in the 2010 nine-month period due to capitalized interest in the prior year period related to the Green Pipeline.

Depletion, Depreciation, and Amortization ("DD&A")
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
In thousands, except per BOE data	2011		2010			2011		2010
DD&A of oil and natural gas properties	$	90,241	$	108,692		$	264,288	$	295,923
Depletion and depreciation of CO2 assets		4,625		4,984			13,803		15,964
Asset retirement obligations		1,456		1,877			4,715		4,676
Depreciation of other fixed assets		5,656		5,668			16,261		15,739
Cumulative change due to revision in policy for CO2 properties		-		(9,619	)		-		(9,619	)
Total DD&A	$	101,978	$	111,602		$	299,067	$	322,683
DD&A per BOE:
Oil and natural gas properties	$	14.91	$	15.46		$	15.13	$	15.35
CO2 assets and other fixed assets		1.68		1.49			1.69		1.62
Cumulative change due to revision in policy for CO2 properties		-		(1.34	)		-		(0.49	)
Total DD&A cost per BOE	$	16.59	$	15.61		$	16.82	$	16.48

Depletion of oil and natural gas properties decreased on an absolute dollars basis during the three and nine months ended September 30, 2011 as compared to the same periods of 2010, primarily due to the sale of non-strategic legacy Encore assets and our ownership interests in ENP during 2010.  DD&A of oil and natural gas properties decreased from $15.85 per BOE in the second quarter of 2011 to $14.91 per BOE during the third quarter of 2011 due primarily to the impact of natural gas reserves added from the Riley Ridge acquisition in the third quarter of 2011.  DD&A per BOE also decreased from the third quarter of 2010 as compared to the third quarter 2011, as reserve additions during the period more than replaced the decline in reserves resulting from the sale of the legacy Encore and ENP properties.

We continually evaluate the performance of our tertiary projects, and if performance indicates that we are reasonably certain of recovering additional reserves from these floods, we recognize those incremental reserves in that quarter.  Since we adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change significantly in the future.

Our DD&A expense for our CO2 assets decreased on an absolute basis for the three and nine months ended September 30, 2011 compared to the same periods in 2010 due to proved CO2 reserve increases at Jackson Dome and Riley Ridge at the end of 2010.  On a per BOE basis, DD&A expense for our CO2 assets and other fixed assets increased for the three and nine months ended September 30, 2011 compared to those in the prior-year quarter due to decreased oil and natural gas production volumes as a result of the sale of non-strategic Encore properties and our interests in ENP during 2010.

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation.  We did not have a ceiling test write-down at September 30, 2011.  However, if oil and natural gas prices were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost pool ceiling test in the future.  The possibility and amount of any future write-down is difficult to predict, and will depend upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures, and additional capital spent.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Encore Transaction and Other Costs

FASC Business Combinations topic requires that all transaction-related costs (advisory, legal, accounting, due diligence, integration, etc.) be expensed as incurred.  We recognized transaction and other costs of $4.4 million during the nine months ended September 30, 2011 associated with the Encore Merger, including $3.6 million related to severance costs.  Transaction and other costs of $11.5 million and $79.3 million for the three and nine months ended September 30, 2010, respectively, included $10.7 million and $31.4 million, respectively, of severance costs, and were significantly higher than 2011 levels.

Income Taxes
	Three Months Ended								Nine Months Ended
	September 30,								September 30,
In thousands, except per BOE amounts and tax rates	2011				2010				2011				2010
Current income tax provision (benefit)		$	(5,331	)		$	3,704			$	5,849			$	11,314
Deferred income tax provision			172,981				16,595				317,601				167,289
Total income tax provision		$	167,650			$	20,299			$	323,450			$	178,603
Average income tax provision per BOE		$	27.27			$	2.84			$	18.19			$	9.12
Effective tax rate			37.8	%			39.4	%			38.3	%			38.8	%

Our income taxes are based on an estimated statutory rate of approximately 38%.  Our effective tax rate for the third quarter of 2011 was slightly lower compared to our statutory rate, primarily due to the recognition of additional tax benefits in our 2010 tax returns in excess of the estimated benefits included in our tax provision at December 31, 2010, offset in part by nondeductible expenses. Excluding this benefit, our effective tax rate would have been closer to 38.3% for the third quarter of 2011. Our effective tax rate for the third quarter of 2010 was higher than our statutory rate due to the recognition of incremental tax expense resulting from the reconciliation of our tax provision to the actual amounts reported on our 2009 tax returns.  The higher effective rate of 38.8% during the nine months ended September 30, 2010 as compared to 38.3% in the nine months ended September 30, 2011, was primarily due to the combined effects of having to remeasure our deferred tax liabilities in conjunction with the Encore Merger in the first quarter of 2010 and the sale the certain of Encore’s Southern Assets in the second quarter of 2010,  which resulted in net incremental income tax expense.  The amount recorded as current income tax expense represents our state income taxes during the three and nine months ended September 30, 2011 and 2010, and for the 2011 periods, federal alternative minimum taxes that we cannot offset with enhanced oil recovery credits. Our third quarter 2011 current income taxes were a net benefit due to the change in treatment for certain items between our 2010 tax provision and our 2010 filed tax return.  This change in treatment resulted in a reclassification of approximately $15 million from current to deferred taxes, which represents refunds that we anticipate related to our 2010 tax period.

As of September 30, 2011, we had an estimated $51.4 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2011 or future years.  The enhanced oil recovery credits do not begin to expire until 2023.  Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.

In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. Henceforth, beginning with the 2011 tax year, we are returning to capitalizing and depreciating the costs of these assets for tax purposes. As a result of the prospective nature of the IRS’s determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are pending review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.

The President’s 2012 budget, as well as certain Congressional legislative initiatives, have proposed repealing many tax incentives for the oil and gas industry. Those items that would have the most significant impact on us would include the loss of the domestic manufacturing deduction, the repeal of the immediate expensing of intangible drilling costs and tertiary injection costs, and the elimination of the percentage depletion allowance; however, we do not believe it would impact any credits that we have earned to date. It is uncertain whether these or similar tax law changes will be enacted, and if so what the effective date of any such changes might be, although the current proposals would not take effect until 2012 or later.  If some or all of these proposals were enacted and included us, they would likely increase the amount of cash taxes that we pay in future periods, and, accordingly, could impact our forecasted capital expenditure budget.

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DENBURY RESOURCES INC.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Per BOE Data

The following table summarizes our cash flow, DD&A, and results of operations on a per BOE basis for the comparative periods.  Each of the individual components is discussed above.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Per BOE data	2011			2010			2011			2010
Oil and natural gas revenues	$	91.98		$	64.44		$	93.52		$	65.34
Gain (loss) on settlements of derivative contracts		0.74			1.40			(0.27	)		(2.40	)
Lease operating expenses		(22.21	)		(18.43	)		(22.13	)		(18.16	)
Production taxes and marketing expenses		(6.01	)		(4.97	)		(6.15	)		(4.75	)
Production netback		64.50			42.44			64.97			40.03
Non-tertiary CO2 operating margin		0.84			0.30			0.65			0.42
General and administrative expenses		(4.70	)		(5.19	)		(5.83	)		(5.16	)
Transactions and other costs related to the Encore Merger		-			(1.60	)		(0.25	)		(4.05	)
Net cash interest expense and other income		(4.80	)		(6.57	)		(5.79	)		(5.27	)
Current income taxes and other		2.34			1.37			0.96			0.92
Changes in assets and liabilities relating to operations		(6.83	)		(1.60	)		(7.52	)		3.37
Cash flow from operations		51.35			29.15			47.19			30.26
DD&A		(16.59	)		(15.61	)		(16.82	)		(16.48	)
Deferred income taxes		(28.13	)		(2.32	)		(17.86	)		(8.54	)
Gain on sale of interests in Genesis		-			-			-			5.18
Loss on early extinguishment of debt		-			-			(0.91	)		-
Non-cash fair value derivative adjustments		33.44			(5.86	)		12.21			9.45
Net income attributable to noncontrolling interest		-			(0.30	)		-			(1.04	)
Changes in assets and liabilities and other non-cash items		4.77			(0.99	)		5.48			(5.49	)
Net income attributable to Denbury stockholders	$	44.84		$	4.07		$	29.29		$	13.34

Critical Accounting Policies

For additional discussion of our critical accounting policies, which remain unchanged, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2010.

Forward-Looking Information

The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties.  Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, dates of pipeline construction commencement and completion, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, timing of CO2 injections and initial production response in tertiary flooding projects, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves, potential reserves from tertiary operations, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and natural gas prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target,” or other words that convey the uncertainty of future events or outcomes.  Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations.  As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf.  Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets, including financial market impact of any European  sovereign or related debt default; changes in interest rates; general economic conditions; competition and government regulations; electronic, cyber or physical security breaches; and unexpected delays, as well as the risks and uncertainties inherent in oil and natural gas drilling and production activities or which are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

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DENBURY RESOURCES INC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Long-term Debt and Interest Rate Sensitivity

We finance some of our acquisitions and other expenditures with fixed and variable-rate debt.  Our Bank Credit Agreement and our senior subordinated notes do not have any triggers or covenants regarding our debt ratings with rating agencies.  Borrowings on our Bank Credit Agreement, which bear interest at variable rates, expose us to market risk related to changes in interest rates.  As of September 30, 2011, our borrowings on our Bank Credit Agreement were $110 million, with a weighted average interest rate of 1.73%.  At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense.

The following table presents the principal balances of our debt, by maturity date, as of September 30, 2011:

In thousands, except percentages	2014		2015		2016		2017		2020		2021
Variable rate debt:
Bank Credit Agreement (weighted average interest rate of 1.73% at September 30, 2011)	$	110,000	$	-	$	-	$	-	$	-	$	-
Fixed rate debt:
9.5% Senior Subordinated Notes due 2016		-		-		224,920		-		-		-
9.75% Senior Subordinated Notes due 2016		-		-		426,350		-		-		-
8.25% Senior Subordinated Notes due 2020		-		-		-		-		996,273		-
6.375% Senior Subordinated Notes due 2021		-		-		-		-		-		400,000
Other Subordinated Notes		1,072		485		-		2,250		-		-

Commodity Derivative Contracts and Commodity Price Sensitivity

From time to time, we enter into oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance (although we will hedge farther in advance if deemed prudent), as we believe it is important to protect our future cash flow for a short period of time in order to give us time to adjust to commodity price fluctuations, particularly since many of our expenditures have long lead times. See Note 4, Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources. 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. All of our commodity derivative contracts are with parties that are lenders under our bank credit agreement. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

For accounting purposes, we do not apply hedge accounting to our commodity derivative contracts.  This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.

At September 30, 2011, our commodity derivative contracts were recorded at their fair value, which was a net asset of approximately $173.1 million (excluding $9.9 million of deferred premiums that Denbury is obligated to pay for its derivative contracts, which payments are not subject to changes in commodity prices), which is a change of approximately $217.1 million from the $44.0 million fair value liability recorded at December 31, 2010.  This change is primarily related to changes in oil futures prices between December 31, 2010 and September 30, 2011.

Based on NYMEX crude oil and natural gas futures prices as of September 30, 2011, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil and natural gas derivative contracts as seen in the following table:

	Crude Oil				Natural Gas
	Derivative				Derivative
	Contracts				Contracts
In thousands	Receipt / (Payment)				Receipt
Based on:
NYMEX futures prices as of September 30, 2011		$	189			$	25,083
10% increase in prices			(2,305	)			20,877
10% decrease in prices			67,018				29,288

Equity Price Sensitivity

Our investment in Vanguard common units is considered an investment in available-for-sale securities, which is recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income.  This investment is thus subject to equity price sensitivity, as fair value is determined by quoted market prices.  We estimate that a hypothetical 10% increase or decrease in quoted market prices for Vanguard common units would result in a $8.2 million unrealized gain or loss, respectively, as of September 30, 2011.

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DENBURY RESOURCES INC.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Company's management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, the Company's Chief Executive Officer and our Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of September 30, 2011, to ensure: that information required to be disclosed in the reports it files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to the Company's management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the third quarter of fiscal 2011, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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DENBURY RESOURCES INC.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item is incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2010.

Item 1A. Risk Factors

Information with respect to the risk factors has been incorporated by reference from Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010.  There have been no material changes to the risk factors since the filing of such Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the third quarter of 2011, made solely in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights:

				Total Number of		Approximate Dollar
	Total			Shares Purchased		Value of Shares
	Number of	Average		as Part of Publicly		that May Yet Be
	Shares	Price Paid		Announced Plans or		Purchased Under the
Month	Purchased	per Share		Programs		Plans or Programs
July 2011	4,042	$	19.49	-	$	-
August 2011	16,298		18.15	-		-
September 2011	3,581		14.63	-		-
Total	23,921		17.85	-	$	-

In addition, in early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company’s Board.  The program has no pre-established ending date, and may be suspended or discontinued at any time.  The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.  Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for $149.3 million, or $13.58 per share under this share repurchase program.

Item 6. Exhibits

Exhibit	Description
4.1	Sixth Amendment to Credit Agreement dated as of March 9, 2010, dated as of September 1, 2011, among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference as Exhibit 10.1 of our Form 8-K filed on September 8, 2011).
10.1*	Officer Resignation Agreement dated as of September 29, 2011.
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data Files

_________

*  Filed herewith.

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DENBURY RESOURCES INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DENBURY RESOURCES INC.
By:	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary
By:	/s/ Alan Rhoades
	Alan Rhoades
	Vice President and Chief Accounting Officer

Date: November 8, 2011

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EX-10.1

Exhibit 10.1

OFFICER RESIGNATION AGREEMENT

THIS OFFICER RESIGNATION AGREEMENT (“Agreement”) is entered into by and between Denbury Resources Inc., a Delaware corporation (the “Company”), and Ronald T. Evans (“Evans”) on September 29, 2011 and will become effective (the “Effective Date”) on the eighth day thereafter.

W I T N E S S E T H:

WHEREAS, Evans has been employed by the Company since September 1999 and has served as an officer of the Company for over ten years, currently serving as the Company’s President and Chief Operating Officer;

WHEREAS, the Company and Evans have reached certain agreements as to the terms and conditions of Evans’ resignation as Chief Operating Officer and President of the Company and his continued employment related to engineering and technical matters; and

WHEREAS, Evans has been in a position of special responsibility and trust with the Company during his employment, with access to highly sensitive, valuable, confidential  and propriety information regarding the Company’s methods of operations, current and future  business plans and strategies, personnel and finances, and other confidential and/or non-public information of the Company;

NOW, THEREFORE, in consideration of the premises and mutual covenants, herein, and other valuable consideration, the sufficiency of which is hereby acknowledged, the Company and Evans agree as follows:

1.Resignation as President and Chief Operating Officer.  Evans and the Company agree that upon the Effective Date, he shall resign as (a) President and Chief Operating Officer of the Company and (b) an officer and director of all other Company subsidiaries, and shall not thereafter serve the Company or its subsidiaries in an officer’s capacity, as a member of the Company’s Investment Committee, or as a director, manager or officer of any Company subsidiary.

2.Resignation Consideration.  In consideration of Evans’ service to the Company over more than twelve years and his role in the Company’s growth over that period, the Company hereby agrees that, subject to appropriate withholding, as provided below, on the Effective Date it will pay Evans $1,900,000 in cash, provided that on or immediately prior to the date on which such payment is to be made to Evans or, if earlier, the date on which an amount is required to be included in the income of Evans as a result of such payments, Evans shall be required to pay to the Company in cash the amount which the Company reasonably determines to be necessary in order for the Company to comply with applicable federal or state tax withholding requirements and the collection of employment taxes.

3.Equity Awards; Cash Awards.  Those equity awards (consisting of an Incentive Stock Option Agreement, a Performance Stock Award, Non-Qualified Stock Option Agreements, Restricted Stock Awards, and Stock Appreciation Rights Agreements) and cash awards (consisting of a Performance Cash Award) held by Evans immediately prior to the Effective Date shall be treated, governed and interpreted according to the terms of such awards, and as applicable, of the Company’s equity compensation plans under which they have been issued, including the vesting provisions thereof, and in a manner which accommodates both Evans’ transition from a full-time employee to a part-time employee under the terms of Section 4 below, and under the terms of Section 1 above his no longer being a member of the Company’s Investment Committee nor an officer of the Company or any of its subsidiaries.

4.Continued Employment.  Evans shall be employed by the Company on a part-time basis for work on engineering and technical matters for the period commencing on the Effective Date and ending April 1, 2014 (the “Employment Period”), and in lieu of and in replacement of Evans’ current salary, during the Employment Period Evans shall be paid a yearly salary at the rate of $48,000 per year in accordance with, and subject to, the Company’s payroll policies that apply to other employees of the Company, including Evans’ continuing participation in the Company’s Christmas bonus program.  Evans’ employment shall not require him to render services to the Company on a full-time basis, but consistent with the provisions of Section 6(d) hereof, on a basis as requested from time to time by the Chairman of the Company’s Board, or by the Company’s Chief Executive Officer, at such places as may reasonably be agreed upon.  In the event that Evans is requested to work more than five (5) days during any calendar month, Evans shall be entitled to be paid an additional $2,000 per day for each additional day worked.

In connection with Evans’ part-time employment by the Company during the Employment Period, Evans shall be entitled to reimbursement for reasonable and necessary expenses incurred in furtherance of the Company’s business in accordance with the Company policies, and upon presentation of documentation in accordance with the expense reimbursement policies of the Company as they may exist from time to time, and submission to the Company of adequate documentation in accordance with federal income tax regulations.

Commencing on the Effective Date, Evans and his qualified beneficiaries shall be entitled to timely elect to continue medical, dental and vision insurance benefits under and through the terms of the applicable COBRA law and regulations, at the Company’s expense, through March 31, 2014.

5.Non-Eligibility for Company Plans.  Other than as set out above, after the Effective Date Evans will not be eligible to receive awards under the Company’s equity compensation plans made available to employees, nor will he be eligible to receive a “Severance Benefit” under the terms of the Company’s Severance Protection Plan.

6.Evans’ Non-Competition and Other Covenants and Agreements.  In consideration of the compensation paid and to be paid to Evans, to which Evans acknowledges he is not otherwise entitled, and the agreements to be performed which are contained herein, Evans agrees to the following covenants as reasonable and necessary for the protection of the Company's business interests:

(a)Definitions:

“Competing Business” means any person or entity that competes with or would compete with or displace, or that engages in any other activities so similar in nature or purpose to those of the Company set forth below so as to compete with, or displace or attempt to compete with or displace (i) in those geographic areas where the Company currently has activities as of the Effective Date or where it anticipates doing future business as part of the Company’s business plan disclosed to or developed by Evans prior to the Effective Date, any of the activities of the Company which involve or encompass the purchase, ownership or development of CO2 reserves, CO2 pipelines, or the injection of CO2 into previously producing oil fields for the purpose of tertiary recovery of remaining oil, or (ii) in the Gulf Coast and Rocky Mountain regions where the Company currently has activities as of the Effective Date, the purchase, ownership or development of oil fields with remaining oil potentially recoverable through CO2 enhanced oil recovery operations, provided that the geographic areas and regions referenced in clauses (i) and (ii) above shall not include areas or regions in Montana and North Dakota where the Company currently has activities involving properties that are prospective for the Bakken formation or play.

“Covered Persons” means any person employed by the Company either as an employee, consultant or advisor, as of September 30, 2011, or hired by the Company prior to April 1, 2014.

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(b)No Unfair Competition; Non-Solicitation Agreement.  Evans agrees that for a period extending until April 1, 2014 or an earlier date, if any, on which there is or is deemed to be "change in control" as defined under the Company's Omnibus Stock and Incentive Plan ("Non-Competition Termination Date"), Evans will not, either directly or indirectly (whether personally or through another business, entity or person):

(i)           work for, supervise, assist or participate in, a Competing Business in any capacity (as owner, employee, consultant, advisor, contractor, officer, director, lender, investor, agent, or otherwise) or otherwise engage in any Competing Business, or

(ii)           either (1) recruit, solicit, or induce, (2) attempt to recruit, solicit or induce, or (3) encourage others to recruit, solicit or induce, any Covered Person to diminish, curtail, divert, or cancel its or their business relationship with, or employment by, the Company, specifically including providing directly or indirectly a reference to a recruiter, acquaintance or competitor that an employee, consultant or advisor to the Company may be amenable to recruitment from a third party.

This Section creates a narrowly tailored restraint in order to avoid unfair competition and irreparable harm to the Company and is not intended or to be construed as a general restraint from engaging in a lawful profession or a general covenant against competition in the oil and gas industry through April 1, 2014.  To this end, within the constraints of the preceding paragraphs of this Section 6(b), the Company agrees that Section 6(b) will not prohibit Evans’ work, engagement, or investment in the oil and gas industry (the “Activities”) so long as (i) the Activities do not involve Evans or entities, persons or groups for whom Evans works, consults or invests (x) competing with or displacing the specified activities of the Company in those geographic areas or regions enumerated above in Section 6(a), or (y) using the Company’s data or non-public business plan disclosed or known to Evans during his employment by the Company, in both cases provided that Evans provides notice to the Chief Executive Officer of the Company of any such work, engagement or investment in such Activities at least 10 business days prior to commencing same, or (ii) Evans obtains the prior unanimous approval of the Company's Investment Committee.

If Evans wishes to pursue the Activities prior to April 1, 2014 (or any earlier Non-Competition Termination Date), he will present to Phil Rykhoek, or his successor as Chief Executive Officer of the Company, a written description of any such proposed Activities.  It is expected that any such proposal shall include, among other things, (i) the geographical area within which Evans desires to pursue the Activities, (ii) the terms of any proposed acquisition of properties or leases, and (iii) if necessary, a complete geological review of the proposal.  The Company agrees to respond in writing to Evans’s request within 10 business days of receipt of such written description, at the address provided in Section 11 below, stating the Company’s approval (which can only be provided by the unanimous approval of its Investment Committee) or disapproval of such Activities and the specific reasons for any disapproval to the extent the Company can do so without disclosing to Evans otherwise non-public information.  The Company agrees not to unreasonably withhold consent to Evans’s request to engage in future Activities.  Further, nothing herein will prohibit ownership of less than 10% of the publicly traded capital stock of an entity so long as this is not a controlling interest, or prohibit ownership of mutual fund investments.

(c)No Personal Use of Company Oil and Gas Resources.  Evans agrees that in conjunction with his continuing employment by the Company, he will not utilize Company oil and gas resources, including, but not limited to, maps, seismic information, feasibility studies, personnel, computers, software, books and records, or any other corporate assets, in connection with the Activities for his own account or the account of any entity, persons or groups for whom he works or consults or in which he invests, unless the Company’s Investment Committee provides its prior express written consent.

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(d)Cooperation and Assistance.In exchange for the compensation, covenants, and other good and valuable consideration provided by the Company herein, Evans agrees that he will during the Employment Period, or an earlier date, if any, on which there is or is deemed to be either a "change in control" as defined under the Company's Omnibus Stock and Incentive Plan (“Non-Competition Termination Date”) (i) make himself reasonably available to the Company to provide assistance to the Company as deemed necessary by the Company from time to time in its business operations; (ii) provide whatever cooperation and/or assistance is needed for any legal matters, proceedings or issues, the Company may face; and (iii) cooperate with and assist the Company and its employees in effecting an orderly transition of all functions, duties and responsibilities of Evans as Chief Operating Officer to one or more other employees of the Company, as the Company shall reasonably request. Additionally, Evans agrees to provide such assistance in a professional manner, and in no event take any action that does, or could reasonably, create a conflict of interest between himself and the Company, or that could subject either him or the Company to civil or criminal liability or is contrary to the policies or procedures of the Company.

(e)Nondisparagement.  The parties hereto agree that they will refrain from engaging in any conduct, verbal or otherwise, that would disparage or harm the reputation of the other or, insofar as this agreement pertains to the Company, its former and present parents, subsidiaries, and/or affiliates, along with its predecessors, successors and/or assigns, if any, as well as their respective former and present officers, directors, managers, general or limited partners, representatives, agents, employees and/or attorneys, if any, jointly and severally (collectively, the “Released Parties”), and Evans further agrees that he will not say anything of a disparaging nature about the operations, management, or performance of the Company.  Such conduct shall include, but not be limited to, any negative statements made orally or in writing by either of the parties about the other or any of the Released Parties.

(f)Confidential Information and Property.  Evans will be entitled to retain the laptop computer, cellular telephone and iPad which he is currently using.  Evans agrees that he has returned, or within three (3) days after the Effective Date will return, to the Company any and all originals and/or copies of documents relating to the business of the Company or any of the other Released Parties, although in conjunction with his part-time employment under the provisions of Section 4 above he may be provided with or have access to Company “confidential information,” which he will return to the Company upon request.  Evans further agrees that he will not directly or indirectly disclose to anyone, or use for his own benefit or the benefit of anyone other than the Company, any “confidential information” that he has received through his employment with the Company.  “Confidential information” shall be information that has been disclosed to, or created by, Evans, and which was at the time of disclosure or creation confidential or proprietary to the Company, and involves the Company's current and future business plans and strategies, methods of operations or operational techniques, management and employee information, information regarding the Company’s practices and processes, or other non-public information.  Evans further agrees that in the event it appears that he will be compelled by law or judicial process to disclose any such confidential information to avoid potential liability, he will notify the Company in writing immediately upon his receipt of a subpoena or other legal process.

7.Mutually Dependent.  The provisions of Section 4 above regarding Evans’ continued employment related to engineering and technical matters and the Company’s continuing obligations to Evans which are related thereto, and the covenants and agreements of Evans set forth in Section 6 above, are mutually dependent, and Evans understands and agrees that a violation of any of the provisions of Section 6 above will be considered a material breach of this Agreement, and further acknowledges and agrees that irreparable harm to the Company would result from breach by him of any such provisions.  Accordingly, notwithstanding any provision of this Agreement to the contrary, Evans will permanently forfeit any rights to continued employment by the Company as set out under the provisions of Section 4 above, and the Company may immediately terminate such employment, beginning on the date that either (i) Evans violates any provision of Section 6 above, or (ii) all or any part of, or the application of, Section 6 above is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in an action between Evans and the Company, and on such date any continuing obligations of the Company to Evans tied to his continued employment shall be extinguished.

- 4 -

8.Release and Waiver by Parties.  For and in consideration of the payments provided to be made under the provisions of Section 2 above, and the continued employment by Evans under the provisions of Section 4 hereof, as well as the covenants contained herein, the receipt and sufficiency of which are hereby acknowledged, Evans, on behalf of himself and his family, assigns, representatives, agents, and/or heirs, if any, hereby covenants not to sue and fully, finally and forever releases, acquits and discharges the Company, along with its former and present parents, subsidiaries, and/or affiliates, along with its predecessors, successors and/or assigns, if any, as well as their respective former and present officers, directors, managers, agents, attorneys, and employees, jointly and severally (collectively, the “Released Parties”), from any and all claims, demands, actions, or liabilities of whatever kind or character, whether known or unknown, which Evans or anyone on his behalf has or might claim to have against the Released Parties for any and all injuries, damages (actual or punitive), losses, attorneys’ fees, if any, incurred by Evans arising out of or in connection with any occurrence which transpired prior to the execution of this Agreement, including, without limitation:

(a)All claims and causes of action arising under contract, tort, statute, or other common law, including, without limitation, breach of contract, fraud, estoppel, misrepresentation, express or implied duties of good faith and fair dealing, wrongful discharge, discrimination, retaliation, harassment, negligence, gross negligence, false imprisonment, assault and battery, conspiracy, intentional or negligent infliction of emotional distress, slander, libel, defamation, refusal to perform an illegal act and invasion of privacy.

(b)All claims and causes of action arising under any federal, state, or local law, regulation, or ordinance, including without limitation, claims under the AGE DISCRIMINATION IN EMPLOYMENT ACT, as amended, the Civil Rights Act of 1964, as amended, the Civil Rights Act of 1866, the Americans With Disabilities Act, the Fair Labor Standards Act, the Family and Medical Leave Act, the Employee Retirement Income Security Act as amended (except for vested benefits to which he is entitled), the Texas Commission on Human Rights Act, the Texas Labor Code, § 451, the Texas Government Code, the Texas Pay Day Law, as well as any claims for compensation of any nature whatsoever, employee benefits, vacation pay, expense reimbursement, consulting, equity awards, severance pay, pension or profit sharing benefits, health or welfare benefits, bonus compensation, commissions, deferred compensation or other remuneration, or employment benefits or compensation, except as specifically set forth in Paragraph 2, “Resignation Consideration,” Paragraph 3, “Equity; Cash Awards,” and Paragraph 4, “Continued Employment.”

(c)All claims and causes of action for past or future loss of pay or benefits, expenses, damages for pain and suffering, mental anguish or emotional distress damages, liquidated damages, punitive damages, compensatory damages, injunctive relief, attorney's fees, interest, court costs, physical or mental injury, damage to reputation, and any other injury, loss, damage or expense or any other legal or equitable remedy of any kind whatsoever.

(d)All claims and causes of action arising out of or in any way connected with, directly or indirectly, Evans’ employment with the Company, or any incident thereof, including, without limitation his treatment by the Company, the terms and conditions of his employment; the manner or amounts in which Evans was paid or compensated by the Company; and the separation of Evans’ employment.

(e)All claims and causes of action of any kind or character which could have been alleged in any lawsuit or administrative charge, claim or proceeding that could have been filed against the Released Parties by Evans on his own behalf or in behalf of any other person.

Evans acknowledges and agrees that the compensation referenced above in Section 2 above does not constitute monies to which he would otherwise be entitled as a result of his prior or current employment with the Company, and that these monies constitute fair and adequate compensation for the promises and covenants of Evans set forth in this Agreement.  Evans agrees and acknowledges that no further amounts are due to him for cash compensation of any nature whatsoever, including salary, severance pay, or bonuses, or for equity awards, employee benefits, deferred compensation, commissions, vacation pay, pension, profit sharing benefits, health or welfare benefits, expense reimbursement, consulting, outplacement services, attorneys' fees, pay in lieu of notice, or for any other amounts, except as specifically set forth in Paragraph 2, “Resignation Consideration,” Paragraph 3, “Equity; Cash Awards,” and Paragraph 4, “Continued Employment.”

The Company also agrees not to sue and fully, finally and forever releases, acquits and discharges Evans from any and all claims, demands, actions or liabilities of whatever kind or character, whether known or unknown as of the Effective Date, which the Company or anyone acting on its behalf has or might claim to have against Evans for any and all injuries, damages (actual and punitive), losses, attorneys’ fees, if any, incurred by the Company.

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9.Consultation with Attorney and Review Period.

(a)Evans is advised, and acknowledges that he has been advised, to consult with an attorney prior to executing this Agreement concerning the meaning, import, and legal significance of this Agreement. Evans acknowledges that he has read this Agreement, as signified by his signature below, and is voluntarily executing the same after, if sought, advice of counsel for the purposes and consideration herein expressed.

(b)Evans affirms and agrees that he has read and understands the foregoing terms of this Agreement; that he is over the age of eighteen (18) years and is otherwise competent to execute this Agreement; that he was given this Agreement on September 22, 2011, and has been given the opportunity to consider and accept this Agreement until 10:00 a.m. on October 14, 2011 by signing it and returning it to Phil Rykhoek, Chief Executive Officer of the Company at the address provided in Section 11 below, after which time it shall expire and be void if not received; that any changes to this Agreement from the one that was initially presented as a result of negotiation between him and the Company, whether material or immaterial, do not restart or extend the running of the applicable 21-day period of time in which he has to sign the Agreement, which date is more than 21 days from the date it was first presented to him; that he is entering into this Agreement knowingly and voluntarily and without any undue influence or pressures; and that it is a full and final resolution of any and all claims, if any, which he may have against the Company as defined above.

(c)Evans acknowledges that he shall be entitled to revoke this Agreement at any time prior to the expiration of seven (7) days after the date he signs this Agreement, by providing written notice of such revocation to Phil Rykhoek, Chief Executive Officer of the Company at the address provided in Section 11 below.

10.Governing Law.  This Agreement shall be governed by and construed under the laws of the State of Texas.

11.Notice.  Any notice, payment, demand or communication required or permitted to be given by this Agreement shall be deemed to have been sufficiently given or served for all purposes if delivered personally to and signed for by the party or to any officer of the party to whom the same is directed or if sent by registered or certified mail, return receipt requested, postage and charges prepaid, addressed to such party at the address set forth below or to such other address as shall have been furnished in writing by such party for whom the communication is intended.  Any such notice shall be deemed to be given on the date so delivered.

Denbury Resources Inc.

5320 Legacy Drive

Plano, TX 75024

Ronald T. Evans

[Redacted]

[Redacted]

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12.Severability.  In the event that any one or more of the provisions contained in this Agreement is for any reason held to be unenforceable in any respect under the laws of any state or of the United States of America, such unenforceability will not affect any other provision of this Agreement, but with respect only to the jurisdiction holding the provision to be unenforceable, this Agreement will then be construed as if such unenforceable provision or provisions had never been contained herein.

13.Entire Agreement.  This Agreement constitutes the sole agreement between the parties and supersedes any and all other agreements, oral or written, relating to the subject matter covered by the Agreement, with the exception of (i) any indemnity agreement which may exist between the Company and Evans, and which indemnity agreement shall remain in force independent of this Agreement, and (ii) the terms of the Company’s equity compensation plans which are not otherwise specifically addressed in this Agreement.

14.Waiver.  Any waiver or breach of any of the terms of this Agreement shall not operate as a waiver of any other breach of such terms or conditions, or any other terms or conditions, nor shall any failure to enforce any provisions hereof operate as a waiver of such provision or any other provision hereof.

15.Assignment.  This Agreement is personal to Evans and the rights and interests of Evans hereunder may not be sold, transferred, assigned or pledged.

16.Successors.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, representatives, successors (including specifically any successor to the Company by merger, reorganization or otherwise).

17.Disputes.

(a)If a dispute arises under this Agreement arising out of, related to or in connection with, the payment of amounts provided hereunder to be paid by the Company to Evans, the timing of such payments or their calculation or, questions regarding the breach of the terms hereof or the issue of arbitrability (a “Dispute”), and the dispute cannot be settled through direct discussions by the parties within a reasonable amount of time, the Company and Evans agree that such disputes shall be referred to and finally resolved by, binding arbitration in accordance with the provisions of Exhibit A hereto.  The Company will pay the actual fees and expenses of the arbitrators, and the parties shall bear equally all other expenses of such arbitration, unless the arbitrators determine that a different allocation would be more equitable.  The award of the arbitrators will be the exclusive remedy of the parties for such disputes.

(b)Jurisdiction and venue of any action relating to this Agreement or Evans’s employment by the Company (subject to the provisions of Section 17(a) hereof), shall be in the state courts of Plano, Collin County, Texas.

IN WITNESS WHEREOF, the parties hereto affixed their signatures hereunder as of the date first above written.

DENBURY RESOURCES, INC.
By:	/s/ Wieland Wettstein
Name:	Wieland Wettstein
Title:	Chairman of the Board of Directors

RONALD T. EVANS

/s/ Ronald T. Evans

- 7 -

EXHIBIT A

DISPUTE RESOLUTION PROCEDURES

1.Applicable Law/Arbitration.  Venue for the arbitration provided under Section 17(b) of the Agreement shall be in Plano, Collin County, Texas.  Except for the limited rights described in Paragraph 9 below, the parties waive their right to file a lawsuit in a court of law to prosecute any Dispute.

2.Negotiation.  When a Dispute has arisen and negotiations have reached an impasse, either party may give the other party written notice of the Dispute. In the event such notice is given, the parties shall attempt to resolve the Dispute promptly by negotiation.  Within ten (10) days after delivery of the notice, the receiving party shall submit to the other a written response. Thereafter, the parties shall promptly attempt to resolve the Dispute. All reasonable requests for information made by one party to the other will be honored.

3.Confidentiality of Settlement Negotiations.  All negotiations and proceedings pursuant to Paragraph 2 above are confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence and any additional confidentiality protections provided by applicable law.

4.Commencement of Arbitration.  If the Dispute has not been resolved by negotiation within fifteen (15) days of the disputing party’s notice, or if the parties have failed to confer within fifteen (15) days after delivery of the notice, either party may then initiate arbitration by providing written notice of arbitration to the other party.  In order to be valid, the notice shall contain a precise and complete statement of the Dispute. Within fifteen (15) days of receipt of the notice initiating arbitration, the receiving party shall respond by providing a written response which shall include its precise and complete response to the Dispute, and which includes any counter Dispute that the responding party may have.

5.Selection of Arbitrator(s).  The arbitration may be conducted and decided by a single person that is mutually agreeable to the parties and knowledgeable and experienced in the type of matter that is the subject of the Dispute if a single arbitrator can be agreed upon by the parties.  If the parties cannot agree on a single arbitrator within ten (10) days of the date of the response to the notice of arbitration, then the arbitration shall be determined by a panel of three (3) arbitrators.  To select the three arbitrators, each party shall, within ten (10) days of the expiration of the foregoing ten day period, select a person that it believes has the qualifications set forth above as its designated arbitrator, and such arbitrators so designated shall mutually agree upon a similarly qualified third person to complete the arbitration panel and serve as its chairman.  In the event that the persons selected by the parties are unable to agree upon a third member of the arbitration panel within ten (10) days after the selection of the latter of the two arbitrators, then he/she shall be selected from the CPR (as defined below) panel using the CPR rules.  Once selected, no arbitrator shall have any ex parte communications with either party.

6.Arbitration Process.  The arbitration hearing shall commence within a reasonable time after the selection of the arbitrator(s), as set by the arbitrator(s).  The arbitrator(s), shall allow the parties to engage in pre-hearing discovery, to include exchanging (i) requests for and production of relevant documents, (ii) up to fifteen (15) interrogatories, (iii) up to fifteen (15) requests for admissions, and producing for deposition and at the arbitration hearing, up to four (4) persons within each parties’ control.  Any additional discovery shall only occur by agreement of the parties or as ordered by the arbitrator(s) upon a finding of good cause.  The arbitration shall be conducted under the rules of the CPR International Institute for Conflict Prevention & Resolution (“CPR”) in effect on the date of notice of the Dispute for dispute resolution rules for non-administered arbitration of business disputes.  The parties may agree on such other rules to govern the arbitration that are not set out in this provision as they may mutually deem necessary.

7.Arbitration Decision.  The arbitrator(s) shall have the power to award interim relief, and to grant specific performance.  The arbitrator(s) may award interest at the “prime rate” as listed under “Market Data” in the Wall Street Journal on the date of any such award.  Except as may be specifically limited elsewhere in this Exhibit A, the arbitrator’s decision may be based on such factors and evidence as the arbitrator(s) deems fit.  The arbitrator(s) shall be required to render a written decision to the parties no later than fifteen (15) days after the completion of the hearing.

8.Arbitration Award.  The award of a majority of the arbitrator(s) shall be final, conclusive and binding.  The award rendered by the arbitrator(s) may be entered in any court having jurisdiction in respect thereof, including any court in which an injunction may have been sought.

9.Injunctive Relief.  With respect to the Dispute, controversy or claim between the parties, nothing in this Exhibit A shall prevent a party from immediately seeking injunctive relief in a court to maintain the status quo during the arbitration.

EX-31.1

DENBURY RESOURCES INC.

Exhibit 31.1

CERTIFICATION UNDER SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Phil Rykhoek, certify that:

1. I have reviewed this quarterly 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.

November 8, 2011	/s/ Phil Rykhoek
	Phil Rykhoek
	Chief Executive Officer

EX-31.2

DENBURY RESOURCES INC.

Exhibit 31.2

CERTIFICATION UNDER SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Mark C. Allen, certify that:

1. I have reviewed this quarterly 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.

November 8, 2011	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

EX-32.1

DENBURY RESOURCES INC.

Exhibit 32

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) of Denbury Resources Inc. (“Denbury”) as filed with the Securities and Exchange Commission on November 8, 2011, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

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.

Dated: November 8, 2011	/s/ Phil Rykhoek
	Phil Rykhoek
	Chief Executive Officer
Dated: November 8, 2011	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Current assets
Allowance for trade and other receivables	$ 274,000	$ 456,000
Stockholders' equity
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	402,625,687	400,291,033
Treasury stock, shares	0	78,524

XML

Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenues and other income
Oil, natural gas, and related product sales	$ 565,523,000	$ 460,785,000	$ 1,662,814,000	$ 1,279,699,000
CO2 sales and transportation fees	6,541,000	4,653,000	16,808,000	13,840,000
Gain on sale of interests in Genesis	0	(3,000)	0	101,537,000
Interest income and other income	4,441,000	1,268,000	12,445,000	7,658,000
Total revenues and other income	576,505,000	466,703,000	1,692,067,000	1,402,734,000
Expenses
Lease operating expenses	136,531,000	131,768,000	393,560,000	355,731,000
Production taxes and marketing expenses	36,949,000	35,542,000	109,388,000	92,959,000
CO2 discovery and operating expenses	1,358,000	2,488,000	5,381,000	5,537,000
General and administrative	28,906,000	37,115,000	103,652,000	101,016,000
Interest, net of amounts capitalized	37,617,000	53,331,000	128,643,000	123,230,000
Depletion, depreciation, and amortization	101,978,000	111,602,000	299,067,000	322,683,000
Derivatives expense (income)	(210,154,000)	31,854,000	(212,308,000)	(138,045,000)
Loss on early extinguishment of debt	0	0	16,131,000	0
Transaction and other costs	0	11,470,000	4,377,000	79,253,000
Total expenses	133,185,000	415,170,000	847,891,000	942,364,000
Income (loss) before income taxes	443,320,000	51,533,000	844,176,000	460,370,000
Income tax provision (benefit)
Current income taxes	(5,331,000)	3,704,000	5,849,000	11,314,000
Deferred income taxes	172,981,000	16,595,000	317,601,000	167,289,000
Consolidated net income (loss)	275,670,000	31,234,000	520,726,000	281,767,000
Less: net income attributable to noncontrolling interest	0	(2,130,000)	0	(20,408,000)
Net income (loss) attributable to Denbury stockholders	$ 275,670,000	$ 29,104,000	$ 520,726,000	$ 261,359,000
Net income (loss) per common share
Basic	$ 0.69	$ 0.07	$ 1.31	$ 0.72
Diluted	$ 0.68	$ 0.07	$ 1.29	$ 0.71
Weighted average common shares outstanding
Basic	399,040,000	395,913,000	398,371,000	362,241,000
Diluted	403,311,000	401,093,000	403,575,000	367,434,000

XML

Supplemental Information (Tables)

9 Months Ended

Sep. 30, 2011

Supplemental Information (Tables) [Abstract]

Accounts Payable and Accrued Liabilities

		September 30,		December 31,
In thousands		2011		2010
Accounts payable		$	107,391	$	47,660
Accrued exploration and development costs			143,647		101,758
Accrued compensation			27,476		39,757
Accrued lease operating expense			30,005		23,557
Accrued interest			28,957		57,077
Taxes payable			19,214		34,371
Deferred Riley Ridge acquisition consideration			15,000		-
Other			33,553		45,888
	Total	$	405,243	$	350,068

Supplemental Cash Flow Information

	Nine Months Ended
	September 30,
In thousands	2011		2010
Cash paid for interest, expensed	$	137,289	$	114,012
Cash paid for interest, capitalized		42,004		56,079
Cash paid for income taxes		36,688		13,691
Cash received for income tax refunds		21,990		13,525
Increase in liabilities for capital expenditures		86,769		13,880
Issuance of Denbury common stock in connection with the Encore Merger		-		2,085,681

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2011
Document And Company Information [Abstract]
Entity Registrant Name	Denbury Resources Inc.
Entity Central Index Key	0000945764
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	391,624,449

XML

Basis of Presentation (Details Textuals) (USD $) Share data in Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Dec. 30, 2010 ENP LP Investment [Member]	Dec. 30, 2010 GP LLC [Member]
Business Acquisition [Line Items]
Ownership percentage in subsidiaries						46.00%	100.00%
Cost basis of investment in VNR					$ 93,000,000
Interest in guarantor subsidiaries	100.00%		100.00%
Basis of Presentation (Textuals) [Abstract]
Net income attributable to noncontrolling interest	0	2,130,000	0	20,408,000
Weighted average common shares - basic restricted stock	3.40	3.40	3.50	3.30
Net unrealized losses on available-for-sale securities, net of tax	3,949,000	0	6,925,000	0
Unrealized loss on short term investment, tax	2,420,000	0	4,244,000	0
Distribution on Vanguard common units	$ 1,800,000		$ 5,300,000

XML

Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 4. Derivative Instruments

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts, and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging fromapproximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.

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. All of our commodity derivative contracts are with parties that are lenders under our BankCredit Agreement.

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

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
In thousands			2011		2010		2011		2010
Oil
	Payment on settlements of derivative contracts		$	1,857	$	3,590	$	23,857	$	80,969
	Fair value adjustments to derivative contracts - expense (income)			(205,355)		62,450		(225,485)		(144,471)
		Total derivative expense (income) - oil		(203,498)		66,040		(201,628)		(63,502)
Natural Gas
	Receipt on settlements of derivative contracts			(6,427)		(13,626)		(19,073)		(34,005)
	Fair value adjustments to derivative contracts - expense (income)			(229)		(19,933)		8,393		(39,041)
		Total derivative expense (income) - natural gas		(6,656)		(33,559)		(10,680)		(73,046)
Ineffectiveness on interest rate swaps				-		(627)		-		(1,497)
		Derivative expense (income)	$	(210,154)	$	31,854	$	(212,308)	$	(138,045)

Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables presentoutstanding commodity derivative contracts with respect to future production as of September 30, 2011

				NYMEX Contract Prices Per Bbl
		Type of		Weighted Average Price
Year	Months	Contract	Bbls/d	Swap		Floor		Ceiling
Oil Contracts
2011	Oct - Dec	Swap	625	$	79.18	$	-	$	-
		Collar	45,500		-		70.33		101.74
		Put	6,625		-		69.53		-
	Total Oct - Dec 2011		52,750
2012	Jan - Mar	Swap	625		81.04		-		-
		Collar	52,000		-		70.00		106.86
		Put	625		-		65.00		-
	Total Jan - Mar 2012		53,250
	Apr-June	Swap	625		81.04		-		-
		Collar	53,000		-		70.00		119.44
		Put	625		-		65.00		-
	Total Apr - June 2012		54,250
	July-Sept	Swap	625		81.04		-		-
		Collar	53,000		-		80.00		128.57
		Put	625		-		65.00		-
	Total July - Sept 2012		54,250
	Oct - Dec	Swap	625		81.04		-		-
		Collar	53,000		-		80.00		128.57
		Put	625		-		65.00		-
	Total Oct - Dec 2012		54,250
2013	Jan - Mar	Collar	16,000		-		70.00		112.66
	Total Jan - Mar 2013		16,000

			Type of		Weighted Average Swap
Year		Months	Contract	MMBtu/d	Price per MMBtu
Natural Gas Contracts
	2011	Oct - Dec	Swap	33,500	$	6.27
		Total Oct - Dec 2011		33,500
	2012	Jan - Dec	Swap	20,000		6.53
		Total Jan - Dec 2012		20,000

Additional Disclosures about Derivative Instruments

At September 30,2011 and December 31, 2010, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

					Estimated Fair Value
					Asset (Liability)
In thousands					September 30,		December 31,
Type of Contract				Balance Sheet Location	2011		2010
Derivatives not designated as hedging instruments:
	Derivative asset
		Oil contracts		Derivative assets - current	$	96,177	$	3,050
		Natural gas contracts		Derivative assets - current		20,584		21,192
		Oil contracts		Derivative assets - long-term		52,627		1,301
		Natural gas contracts		Derivative assets - long-term		3,833		11,618
	Derivative liability
		Oil contracts		Derivative liabilities - current		(60)		(55,256)
		Deferred premiums		Derivative liabilities - current		(9,193)		(22,928)
		Oil contracts		Derivative liabilities - long-term		(70)		(25,906)
		Deferred premiums		Derivative liabilities - long-term		(662)		(3,781)
			Total derivatives not designated as hedging instruments		$	163,236	$	(70,710)

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Acquisitions and Divestitures (Details) (USD $)	Sep. 30, 2011	Dec. 31, 2010	Aug. 01, 2011 Riley Ridge Phase 2 [Member]
Riley Ridge Purchase Price Allocation
Cash payment			$ 199,554,000
Deferred payment	15,000,000	0	15,000,000
Total consideration			214,554,000
Oil and natural gas properties - proved			48,731,000
Oil and natural gas properties - unproved			12,542,000
CO2 and other non-hydrocarbon gases properties			9,741,000
Pipelines and plants			91,594,000
Other assets			48,660,000
Asset retirement obligations			(389,000)
Business Acquisition Purchase Price Allocation Assets Acquired Liabilities Assumed Excluding Contingent Consideration			210,879,000
Goodwill			3,675,000
Helium extraction rights			$ 36,700,000

XML

Supplemental Information (Details) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Accounts Payable and Accrued Liabilities
Accounts payable	$ 107,391,000	$ 47,660,000
Accrued exploration and development costs	143,647,000	101,758,000
Accrued compensation	27,476,000	39,757,000
Accrued lease operating expense	30,005,000	23,557,000
Accrued interest	28,957,000	57,077,000
Taxes payable	19,214,000	34,371,000
Deferred Riley Ridge acquisition consideration	15,000,000	0
Other Accrued Liabilities Current	33,553,000	45,888,000
Total	$ 405,243,000	$ 350,068,000

XML

Basis of Presentation (Details 1)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Stock Options and SARs [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	4,731,000	4,270,000	3,108,000	4,613,000
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	139,000	69,000	56,000	298,000

XML

Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2011

Policy Text Block [Abstract]

Interim Financial Statements - Basis of Accounting

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 (“U.S. GAAP”) 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, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Interim Financial Statements - Use of Estimates

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2011,ourconsolidated results of operations for thethree and nine months ended September 30, 2011 and 2010, and our consolidated cash flows for the nine months ended September 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Noncontrolling Interest

Noncontrolling Interest

From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP's general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2010. As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2010, “Net income attributable to noncontrolling interest” of $2.1million and $20.4million, respectively, represents ENP's results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.

Net Income Per Common Share

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to our stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For thethree and nine months ended September 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share.

Basic weighted average common shares excludes 3.4million and 3.5million shares for the three and nine months ended September 30, 2011, respectively, and 3.4 million and 3.3 million sharesfor the three and nine months endedSeptember 30,2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant. For purposes of calculating diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
In thousands	2011	2010	2011	2010
Stock options and SARs	4,731	4,270	3,108	4,613
Restricted stock	139	69	56	298

Short-term Investments

Short-term Investments

Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30,2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $3.9 million (net ofa taxbenefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months endedSeptember 30,2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Derivatives, Policy [Policy Text Block]

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts, and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging fromapproximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.

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. All of our commodity derivative contracts are with parties that are lenders under our BankCredit Agreement.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

•       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. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, 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. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.

•       Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g.,Houston Ship Channel).

We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Other comprehensive income (loss), net of income tax:
Tax effect of changes in value on available-for-sale securities	$ (2,420,000)	$ 0	$ (4,244,000)	$ 0
Tax for interest rate lock derivative contracts reclassified to income	11,000	11,000	32,000	32,000
Tax for change in fair value of interest rate lock derivative contracts designated as a hedge	$ 0	$ 14,000	$ 0	$ 32,000

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Fair Value Measurements (Details) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments	$ 81,851,000	$ 93,020,000
Oil and natural gas derivative contracts	173,221,000	37,161,000
Oil and natural gas derivative contracts	(130,000)	(81,162,000)
Total	254,942,000	49,019,000
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments	81,851,000	93,020,000
Oil and natural gas derivative contracts	0	0
Oil and natural gas derivative contracts	0	0
Total	81,851,000	93,020,000
Significant Other Observable Inputs (Level 2) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments	0	0
Oil and natural gas derivative contracts	166,244,000	20,683,000
Oil and natural gas derivative contracts	(130,000)	(81,162,000)
Total	166,114,000	(60,479,000)
Significant Unobservable Inputs (Level 3) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments	0	0
Oil and natural gas derivative contracts	6,977,000	16,478,000
Oil and natural gas derivative contracts	0	0
Total	$ 6,977,000	$ 16,478,000

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Supplemental Information

9 Months Ended

Sep. 30, 2011

Supplemental Information [Abstract]

Supplemental Information

Note 6. Supplemental Information

Accounts Payable and Accrued Liabilities

The following table summarizes ouraccounts payable and accrued liabilitiesas of the periods indicated:

		September 30,		December 31,
In thousands		2011		2010
Accounts payable		$	107,391	$	47,660
Accrued exploration and development costs			143,647		101,758
Accrued compensation			27,476		39,757
Accrued lease operating expense			30,005		23,557
Accrued interest			28,957		57,077
Taxes payable			19,214		34,371
Deferred Riley Ridge acquisition consideration			15,000		-
Other			33,553		45,888
	Total	$	405,243	$	350,068

Supplemental Cash Flow Information

The following table sets forth supplemental cash flow information for the periods indicated:

	Nine Months Ended
	September 30,
In thousands	2011		2010
Cash paid for interest, expensed	$	137,289	$	114,012
Cash paid for interest, capitalized		42,004		56,079
Cash paid for income taxes		36,688		13,691
Cash received for income tax refunds		21,990		13,525
Increase in liabilities for capital expenditures		86,769		13,880
Issuance of Denbury common stock in connection with the Encore Merger		-		2,085,681

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block Supplement [Abstract]

Riley Ridge Purchase Price Allocation

In thousands
Consideration:
	Cash payment		$	199,554
	Deferred payment(1)			15,000
		Total consideration		214,554
Less: Fair value of assets and liabilities acquired:(2)
	Oil and natural gas properties
		Proved		48,731
		Unevaluated		12,542
	CO2 and other non-hydrocarbon gases properties			9,741
	Pipelines and plants			91,594
	Other assets(3)			48,660
	Asset retirement obligations			(389)
				210,879
Goodwill			$	3,675
(1)		The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property’s gas plant is operational and meets specific performance conditions as described above.
(2)		Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments.
(3)		Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned primarily by the Federal government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the future net revenues associated with the Company’s right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis.

Proforma revenue and net income (loss)

		Pro Forma Results
In thousands, except per share amounts		Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
Pro forma total revenues		$	466,703	$	1,579,184
Pro forma net income attributable to Denbury stockholders			29,104		276,527
Pro forma net income per common share:
	Basic	$	0.07	$	0.70
	Diluted		0.07		0.69

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 7. Commitments and Contingencies

In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three contracts are in addition to thepreviously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions. Under the three new contracts, Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC's Medicine Bow Fuel and Power LLC ("MBFP") project near Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("Mississippi Power") project in Mississippi, and purchase 100% of the CO2 captured byAir Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas.  Thesenew contracts each have an initial term of 15 to 16 years and include options to extend the term.We estimate that thesenew sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 100 MMCF/d of CO2 from the MBFP project in2015, 115 MMcf/d of CO2 from the Mississippi Power project by 2014, and 50 MMcf/d of CO2 from Air Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price.  The purchase price of CO2 will fluctuate based on the changes in the price of oil. 

As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies.TheMississippi Power and Air Products plants are currently being constructed, and the MBFP project is contingent upon securing debt financing, equity commitments and receipt of all necessary consents and approvals.

In conjunction with the August 1, 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third party purchaser.Subsequently, we amended this contract to provide for annual delivery (to the 8/8ths working interest) of 127 MMcf of helium (previously 200 MMcf) during the first two years of the contract and thereafter provides for delivery of400 MMcf of helium per year.  If the contracted quantity of helium is not supplied, we are obligated to compensate the third party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year.

In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. As a result of the prospective nature of the IRS's determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are subject to review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.

We are subject to audits for sales and use taxes and severance taxesin the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. Currently, we have no material assessments for potential taxes.

We are involved invarious lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

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Derivative Instruments and Hedging Activities (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Ineffectiveness on interest rate swaps	$ 0	$ (627,000)	$ 0	$ (1,497,000)
Derivatives expense (income)	(210,154,000)	31,854,000	(212,308,000)	(138,045,000)
Oil contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Payment (receipt) on settlements of derivative contracts	1,857,000	3,590,000	23,857,000	80,969,000
Fair value adjustments to derivative contracts - expense (income)	(205,355,000)	62,450,000	(225,485,000)	(144,471,000)
Total derivatives expense (income) - oil & natural gas	(203,498,000)	66,040,000	(201,628,000)	(63,502,000)
Natural Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Payment (receipt) on settlements of derivative contracts	(6,427,000)	(13,626,000)	(19,073,000)	(34,005,000)
Fair value adjustments to derivative contracts - expense (income)	(229,000)	(19,933,000)	8,393,000	(39,041,000)
Total derivatives expense (income) - oil & natural gas	$ (6,656,000)	$ (33,559,000)	$ (10,680,000)	$ (73,046,000)

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Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value, Assets and Liabilities Measured on Recurring Basis [Abstract]

Fair Value Measurements

Note 5. Fair Value Measurements

Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

•       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. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, 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. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.

•       Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g.,Houston Ship Channel).

We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's 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:

Note 5. Fair Value Measurements

Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

•       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. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, 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. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.

•       Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g.,Houston Ship Channel).

We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's 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:
					Significant
			Quoted Prices		Other		Significant
			in Active		Observable		Unobservable
			Markets		Inputs		Inputs
In thousands			(Level 1)		(Level 2)		(Level 3)		Total
September 30, 2011
Assets
	Short-term investments		$	81,851	$	-	$	-	$	81,851
	Oil and natural gas derivative contracts			-		166,244		6,977		173,221
Liabilities
	Oil and natural gas derivative contracts			-		(130)		-		(130)
		Total	$	81,851	$	166,114	$	6,977	$	254,942
December 31, 2010
Assets
	Short-term investments		$	93,020	$	-	$	-	$	93,020
	Oil and natural gas derivative contracts			-		20,683		16,478		37,161
Liabilities
	Oil and natural gas derivative contracts			-		(81,162)		-		(81,162)
		Total	$	93,020	$	(60,479)	$	16,478	$	49,019

The following table summarizes the changes in the fair value of our Level 3 assets for the three and nine months endedSeptember 30, 2011 and 2010

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
In thousands		2011		2010		2011		2010
Balance, beginning of period		$	6,638	$	40,283	$	16,478	$	-
	Unrealized gains (losses) on commodity derivative contracts included in earnings		1,717		20,103		(5,359)		35,002
	Commodity derivative contracts acquired from Encore		-		-		-		38,093
	Receipts on settlement of commodity derivative contracts		(1,378)		(9,035)		(4,142)		(21,744)
Balance, end of period		$	6,977	$	51,351	$	6,977	$	51,351

Since we donot use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements. See Note 3, Long-Term Debtand Item 3, Quantitative and Qualitative Disclosures about Market Riskfor further information about these financial instruments.

		September 30, 2011				December 31, 2010
		Carrying		Estimated		Carrying		Estimated
In thousands		Amount		Fair Value		Amount		Fair Value
	7½% Senior Subordinated Notes due 2013	$	-	$	-	$	224,563	$	228,375
	7½% Senior Subordinated Notes due 2015		-		-		300,427		310,500
	9½% Senior Subordinated Notes due 2016		237,458		242,914		239,509		249,661
	9¾% Senior Subordinated Notes due 2016		407,425		460,458		404,211		475,380
	8¼% Senior Subordinated Notes due 2020		996,273		1,046,087		996,273		1,080,956
	6⅜% Senior Subordinated Notes due 2021		400,000		388,000		-		-

The fair values of our senior subordinated notes are based on quoted market prices.We have other financial instruments consisting primarily of cash, cash equivalents, our Bank Credit Agreement, and short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash flows from operating activities
Consolidated net income (loss)	$ 520,726,000	$ 281,767,000
Adjustments needed to reconcile to net cash provided by operating activities
Depletion, depreciation, and amortization	299,067,000	322,683,000
Deferred income taxes	317,601,000	167,289,000
Gain on sale of interests in Genesis	0	(101,537,000)
Stock-based compensation	27,520,000	27,326,000
Non-cash fair value derivative adjustments	(217,092,000)	(185,009,000)
Loss on early extinguishment of debt	16,131,000	0
Other, net	9,024,000	14,254,000
Changes in operating assets and liabilities:
Accrued production receivable	(45,017,000)	48,453,000
Trade and other receivables	(53,012,000)	20,548,000
Other assets	2,818,000	1,106,000
Accounts payable and accrued liabilities	(65,407,000)	8,257,000
Oil and natural gas production payable	40,819,000	10,553,000
Increase (Decrease) in Other Operating Liabilities	(14,086,000)	(22,915,000)
Net cash provided by operating activities	839,092,000	592,775,000
Cash flows used for investing activities
Oil and natural gas capital expenditures	(741,256,000)	(500,062,000)
Acquisitions of oil and natural gas properties	(34,291,000)	(24,390,000)
Cash paid to acquire a business, net of cash acquired	(199,233,000)	(813,894,000)
CO2 and other non-hydrocarbon gases capital expenditures	(65,866,000)	(67,328,000)
Pipelines and plants capital expenditures	(142,406,000)	(169,157,000)
Net proceeds from sales of oil and natural gas properties and equipment	47,598,000	909,986,000
Net proceeds from sale of interests in Genesis	0	162,619,000
Payments for (proceeds from) other investing activities	(22,798,000)	(17,927,000)
Net cash used for investing activities	(1,158,252,000)	(520,153,000)
Cash flows from financing activities
Bank repayments	(255,000,000)	(1,519,000,000)
Bank borrowings	365,000,000	1,229,000,000
Repayment of senior subordinated notes	(525,000,000)	(609,424,000)
Premium paid on repayment of senior subordinated notes	(13,137,000)	(7,213,000)
Net proceeds from issuance of senior subordinated notes	400,000,000	1,000,000,000
Net proceeds from issuance of common stock	12,348,000	8,614,000
Costs of debt financing	(13,104,000)	(76,232,000)
ENP distributions to noncontrolling interest	0	(24,513,000)
Other	(9,453,000)	(8,100,000)
Net cash provided by (used for) financing activities	(38,346,000)	(6,868,000)
Net increase (decrease) in cash and cash equivalents	(357,506,000)	65,754,000
Cash and cash equivalents at beginning of period	381,869,000	20,591,000
Cash and cash equivalents at end of period	$ 24,363,000	$ 86,345,000

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Basis of Presentation

9 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Note 1. Basis of Presentation

Organization and Nature of Operations

We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the RockyMountain and GulfCoast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) 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, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2011,ourconsolidated results of operations for thethree and nine months ended September 30, 2011 and 2010, and our consolidated cash flows for the nine months ended September 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Noncontrolling Interest

From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP's general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2010. As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2010, “Net income attributable to noncontrolling interest” of $2.1million and $20.4million, respectively, represents ENP's results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to our stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For thethree and nine months ended September 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the periods indicated:

		Three Months Ended		Nine Months Ended
		September 30,		September 30,
In thousands		2011	2010	2011	2010
Basic weighted average common shares		399,040	395,913	398,371	362,241
Potentially dilutive securities:
	Stock options and SARs	2,954	3,647	3,818	3,772
	Performance equity awards	41	292	22	305
	Restricted stock	1,276	1,241	1,364	1,116
Diluted weighted average common shares		403,311	401,093	403,575	367,434

Basic weighted average common shares excludes 3.4million and 3.5million shares for the three and nine months ended September 30, 2011, respectively, and 3.4 million and 3.3 million sharesfor the three and nine months endedSeptember 30,2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant. For purposes of calculating diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
In thousands	2011	2010	2011	2010
Stock options and SARs	4,731	4,270	3,108	4,613
Restricted stock	139	69	56	298

Short-term Investments

Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30,2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $3.9 million (net ofa taxbenefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months endedSeptember 30,2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Short-term Investments

Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At September 30,2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $3.9 million (net ofa taxbenefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months endedSeptember 30,2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Recently Issued Accounting Pronouncements

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, Testing Goodwill for Impairment, (“ASU 2011-08”). ASU 2011-08 amends the FASC Intangibles – Goodwill and Other topic bypermitting entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in the FASC Intangibles – Goodwill and Other topic. We adoptedASU 2011-08 and will apply the guidance prospectively to interim and annual goodwill impairment tests.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend presentation requirements, it will not have a material effect on our consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.

XML

Commitments and Contingencies (Details) (USD $)	9 Months Ended
	Sep. 30, 2011
Long-term Purchase Commitment [Line Items]
Expected amount of CO2 to be delivered by third parties in future years	365 MMcf/d
Maximum annual payment in the event that guaranteed helium is not supplied	$ 8,000,000
Commitments and Contingencies (Textuals) [Abstract]
Tax refund due to change in tax accounting method	10,600,000
Air Products Llc Anthropogenic Contract [Member]
Long-term Purchase Commitment [Line Items]
Percentage of third party's CO2 which we are obligated to purchase	100.00%
Expected amount of CO2 to be delivered by third parties in future years	50 MMcf/d of CO2 from Air Products in late 2012
Medicine Bow Fuel and Power Anthropogenic Contract [Member]
Long-term Purchase Commitment [Line Items]
Percentage of third party's CO2 which we are obligated to purchase	100.00%
Expected amount of CO2 to be delivered by third parties in future years	100 MMCF/d of CO2 from the MBFP project in 2015
Mississippi Power Company Anthropogenic Contract [Member]
Long-term Purchase Commitment [Line Items]
Percentage of third party's CO2 which we are obligated to purchase	70.00%
Expected amount of CO2 to be delivered by third parties in future years	115 MMcf/d of CO2 from the Mississippi Power project by 2014
Anthropogenic Co2 Contracts [Member]
Long-term Purchase Commitment [Line Items]
Purchase obligation term	15 to 16 years
Aggregate purchase obligation of CO2	110,000,000
Oil price assumption for obligation estimate	$ 100
Amount which we may be contractually obligated to purchase	460
Helium Contract Years 1 And 2 [Member]
Long-term Purchase Commitment [Line Items]
Annual delivery of helium under supply agreement	127
Helium Contract Years 3 Through 20 [Member]
Long-term Purchase Commitment [Line Items]
Annual delivery of helium under supply agreement	400
Helium Contract Previous Terms Years 1 And 2 [Member]
Long-term Purchase Commitment [Line Items]
Annual delivery of helium under supply agreement	200

XML

Long Term Debt (Details Textuals) (USD $)	3 Months Ended		9 Months Ended						1 Months Ended					1 Months Ended						9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Mar. 31, 2010	Sep. 30, 2011 7.5% Senior Subordinated Notes due 2013 [Member]	Feb. 28, 2011 7.5% Senior Subordinated Notes due 2013 [Member]	Dec. 31, 2010 7.5% Senior Subordinated Notes due 2013 [Member]	Mar. 31, 2011 7.5% Senior Subordinated Notes due 2013 [Member] Extinguishment One [Member]	Apr. 30, 2011 7.5% Senior Subordinated Notes due 2013 [Member] Extinguishment Two [Member]	Sep. 30, 2011 7.5% Senior Subordinated Notes due 2015 [Member]	Feb. 28, 2011 7.5% Senior Subordinated Notes due 2015 [Member]	Dec. 31, 2010 7.5% Senior Subordinated Notes due 2015 [Member]	Mar. 31, 2011 7.5% Senior Subordinated Notes due 2015 [Member] Extinguishment One [Member]	Mar. 31, 2011 7.5% Senior Subordinated Notes due 2015 [Member] Extinguishment Two [Member]	Sep. 30, 2011 9.5% Senior Subordinated Notes due 2016 [Member]	Dec. 31, 2010 9.5% Senior Subordinated Notes due 2016 [Member]	Sep. 30, 2011 9.75% Senior Subordinated Notes due 2016 [Member]	Dec. 31, 2010 9.75% Senior Subordinated Notes due 2016 [Member]	Sep. 30, 2011 6 3/8% Senior Subordinated Notes Due 2021 [Member]	Feb. 28, 2011 6 3/8% Senior Subordinated Notes Due 2021 [Member]	Sep. 30, 2011 Other Subordinated Notes [Member]	Dec. 31, 2010 Other Subordinated Notes [Member]
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries	100.00%		100.00%
Debt Instrument, Interest Rate Terms			the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months
Commitment fee incurred			ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base
Line of Credit Facility, Covenant Terms			adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x
Maturity date of Denbury Credit Agreement			May 2016
Debt Instrument Redemption Price In Year Five																				103.188%
Debt Instrument Redemption Price Prior to Year Five			equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest
Debt Instrument Carrying Amount																					$ 400,000,000
Interest Rate on Senior Subordinated Notes																				6.375%
Debt Instrument, Unamortized Discount						0		437,000										18,925,000	22,139,000
Principal amount of notes for which cash tender offers commenced							225,000,000					300,000,000
Borrowing Base of Denbury credit agreement					1,600,000,000
Debt Instrument, Unamortized Premium											0		427,000			12,538,000	14,589,000					35,000	41,000
Net proceeds used for repurchase of notes			393,000,000
Debt Instrument Redemption Price In Year Six																				102.125%
Debt Instrument Redemption Price In Year Seven																				101.062%
Debt Instrument Redemption Price In Year Eight																				100.00%
Debt Instrument Redemption Percentage Of Principal Prior To Year Three																				35.00%
Debt Instrument Redemption Price Before Year Three With Equity Offering Proceeds																				106.375%
Debt Instrument Redemption Percentage Of Principal Prior To Year Five With Make-Whole Premium																				100.00%
Extinguishment of Debt [Line Items]
Extinguishment of Senior Notes									169,600,000	55,400,000				220,900,000	79,100,000
Redemption percentage of debt									100.625%	100.00%				104.125%	103.75%
Loss on early extinguishment of debt	$ 0	$ 0	$ 16,131,000	$ 0

XML

Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2011

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 2. Acquisitions and Divestitures

Acquisitions

October 2010 and August 2011 Acquisitions of Reservesin Rocky Mountain Region at Riley Ridge

In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after closing adjustments. RileyRidge contains natural gas resources, as well as helium and CO2resources. The purchase included a42.5% interest in a gas plant, currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also included approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit. The fair values assigned to assets acquired and liabilities assumed in the October 2010 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2010.

On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge not already owned, the remaining 57.5% interest in the gas plantand a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $214.6 million after preliminary closing adjustments, including a $15 million deferred payment to be made at the time the property's gas plant is operational and meets specific performance conditions. We expect the gas plant to be operational during the latter part of the first quarter of 2012.

Because the Riley Ridge plant is currently under construction, current production at the field is negligible. As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011 and 2010.

TheAugust 1, 2011 acquisitionof Riley Ridge meets the definition of a business under the FASC Business Combinations topic. The following table presents a summary of thefair value of the Riley Ridge assets acquired and liabilities assumedon August 1, 2011:

In thousands
Consideration:
	Cash payment		$	199,554
	Deferred payment(1)			15,000
		Total consideration		214,554
Less: Fair value of assets and liabilities acquired:(2)
	Oil and natural gas properties
		Proved		48,731
		Unevaluated		12,542
	CO2 and other non-hydrocarbon gases properties			9,741
	Pipelines and plants			91,594
	Other assets(3)			48,660
	Asset retirement obligations			(389)
				210,879
Goodwill			$	3,675
(1)		The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property’s gas plant is operational and meets specific performance conditions as described above.
(2)		Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments.
(3)		Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned primarily by the Federal government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the future net revenues associated with the Company’s right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis.

2010 Merger with Encore Acquisition Company

On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.

For the three months ended September 30,2010 and for the period from March 9, 2010 to September 30,2010, we recognized $174.3 million and $435.2 million, respectively, of oil, natural gas sales and related product sales from properties acquired as part of the Encore Merger. For the three months ended September 30,2010 and for the period from March 9, 2010 to September 30,2010, we recognized $114.1 million and $294.8 million, respectively,of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) from properties acquired as part of the Encore Merger. We recognized a total of $11.5 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended September 30, 2010, and $4.4 million and $79.3 million of such costs for the nine months ended September 30,2011 and 2010, respectively.

Pro Forma Information

Had the Encore Merger occurred on January 1, 2010, our combined pro forma revenues and net income for the three and nine months ended September 30, 2010, would have been as follows:

2010 Merger with Encore Acquisition Company

On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.

For the three months ended September 30,2010 and for the period from March 9, 2010 to September 30,2010, we recognized $174.3 million and $435.2 million, respectively, of oil, natural gas sales and related product sales from properties acquired as part of the Encore Merger. For the three months ended September 30,2010 and for the period from March 9, 2010 to September 30,2010, we recognized $114.1 million and $294.8 million, respectively,of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) from properties acquired as part of the Encore Merger. We recognized a total of $11.5 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended September 30, 2010, and $4.4 million and $79.3 million of such costs for the nine months ended September 30,2011 and 2010, respectively.

Pro Forma Information

Had the Encore Merger occurred on January 1, 2010, our combined pro forma revenues and net income for the three and nine months ended September 30, 2010, would have been as follows:

		Pro Forma Results
In thousands, except per share amounts		Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
Pro forma total revenues		$	466,703	$	1,579,184
Pro forma net income attributable to Denbury stockholders			29,104		276,527
Pro forma net income per common share:
	Basic	$	0.07	$	0.70
	Diluted		0.07		0.69

Divestitures

2010 Sale of Interests in Genesis

In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (“Genesis”), for net proceeds of approximately $84 million. In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.

2010 Sales of Non-Strategic Legacy Encore Properties

In May 2010, we sold certain non-strategic legacy Encore properties, primarily located in the Permian Basin, the Mid-continent area and the East Texas Basin (the “Southern Assets”), to Quantum Resources Management, LLC for consideration of $892.1 million after closing adjustments. In August 2010, we sold additionallegacy Encore properties, primarily located in the Cleveland Sand Play of western Oklahoma, for consideration of $32.1 million after closing adjustments.We did not record a gain or loss on the sales in accordance with the full cost method of accounting.

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Acquisitions and Divestitures (Details 1) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2010
Proforma revenue and net income (loss)
Pro forma total revenues	$ 466,703,000	$ 1,579,184,000
Pro forma net income attributable to Denbury stockholders	$ 29,104,000	$ 276,527,000
Pro forma net income per common share:
Basic	$ 0.07	$ 0.70
Diluted	$ 0.07	$ 0.69

XML

Derivative Instruments and Hedging Activities (Details 1)	Sep. 30, 2011
Year 2011 [Member] | Collars [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	70.33
Ceiling price	101.74
Volume per Day	45,500
Year 2011 [Member] | Swap [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	79.18
Floor price	0
Ceiling price	0
Volume per Day	625
Year 2011 [Member] | Swap [Member] | Natural Gas Contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	6.27
Volume per Day	33,500
Year 2011 [Member] | Put [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	69.53
Ceiling price	0
Volume per Day	6,625
Year 2011 [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	52,750
Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	70.00
Ceiling price	106.86
Volume per Day	52,000
Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	70.00
Ceiling price	119.44
Volume per Day	53,000
Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	80.00
Ceiling price	128.57
Volume per Day	53,000
Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	80.00
Ceiling price	128.57
Volume per Day	53,000
Year 2012 [Member] | Swap [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	81.04
Floor price	0
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Swap [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	81.04
Floor price	0
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Swap [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	81.04
Floor price	0
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Swap [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	81.04
Floor price	0
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Swap [Member] | Natural Gas Contracts [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	6.53
Volume per Day	20,000
Year 2012 [Member] | Put [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	65.00
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Put [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	65.00
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Put [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	65.00
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Put [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	65.00
Ceiling price	0
Volume per Day	625
Year 2012 [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	53,250
Year 2012 [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	54,250
Year 2012 [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	54,250
Year 2012 [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	54,250
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	70.00
Ceiling price	112.66
Volume per Day	16,000
Year 2013 [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	16,000

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Subsequent Events (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended
	Oct. 31, 2011
Subsequent Event [Line Items]
Stock Repurchase Program, Authorized Amount	$ 500.00
Share Repurchase Program [Member]
Subsequent Event [Line Items]
Treasury Stock Acquired, Average Cost Per Share	$ 13.58
Treasury Stock, Shares, Acquired	10,990,939
Treasury Stock, Value, Acquired, Cost Method	$ 149.30
Treasury Stock Acquired, Percentage of Outstanding	2.70%

XML

Long-Term Debt (Details) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Credit Agreement	$ 110,000,000	$ 0
Capital Lease Obligations	5,010,000	6,806,000
Total	2,404,726,000	2,424,156,000
Less current obligations	8,177,000	7,948,000
Long-term debt and capital lease obligations	2,396,549,000	2,416,208,000
7.5% Senior Subordinated Notes due 2013 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	0	224,563,000
7.5% Senior Subordinated Notes due 2015 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	0	300,427,000
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	237,458,000	239,509,000
9.75% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	407,425,000	404,211,000
6 3/8% Senior Subordinated Notes Due 2021 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	400,000,000	0
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	996,273,000	996,273,000
Other Subordinated Notes [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	3,841,000	3,848,000
NEJD Financing [Member]
Debt Instrument [Line Items]
Financing Lease Obligations	164,626,000	167,331,000
Free State Financing [Member]
Debt Instrument [Line Items]
Financing Lease Obligations	$ 80,093,000	$ 81,188,000

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Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2011

Basis of Presentation (Tables) [Abstract]

Weighted average shares used in the basic and diluted net income per common share

		Three Months Ended		Nine Months Ended
		September 30,		September 30,
In thousands		2011	2010	2011	2010
Basic weighted average common shares		399,040	395,913	398,371	362,241
Potentially dilutive securities:
	Stock options and SARs	2,954	3,647	3,818	3,772
	Performance equity awards	41	292	22	305
	Restricted stock	1,276	1,241	1,364	1,116
Diluted weighted average common shares		403,311	401,093	403,575	367,434

Anti-dilutive securities excluded from computation of diluted net earnings per share

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
In thousands	2011	2010	2011	2010
Stock options and SARs	4,731	4,270	3,108	4,613
Restricted stock	139	69	56	298

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Long-Term Debt

9 Months Ended

Sep. 30, 2011

Long-Term Debt [Abstract]

Long-Term Debt

Note 3. Long-Term Debt

The following table shows the components of ourlong-term debt:

		September 30,		December 31,
In thousands		2011			2010
Bank Credit Agreement		$	110,000		$	-
7½% Senior Subordinated Notes due 2013, including discount of $437			-			224,563
7½% Senior Subordinated Notes due 2015, including premium of $427			-			300,427
9½% Senior Subordinated Notes due 2016, including premium of $12,538 and $14,589, respectively			237,458			239,509
9¾% Senior Subordinated Notes due 2016, including discount of $18,925 and $22,139, respectively			407,425			404,211
8¼% Senior Subordinated Notes due 2020			996,273			996,273
6⅜% Senior Subordinated Notes due 2021			400,000			-
Other Subordinated Notes, including premium of $35 and $41, respectively			3,841			3,848
NEJD Pipeline financing			164,626			167,331
Free State Pipeline financing			80,093			81,188
Capital lease obligations			5,010			6,806
	Total		2,404,726			2,424,156
	Less current obligations		(8,177)			(7,948)
	Long-term debt and capital lease obligations	$	2,396,549		$	2,416,208

The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors is100% owned by DRI;any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries,and the subsidiary guarantors fully and unconditionally guarantee our senior subordinated debt jointly and severally.

Bank Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders as party thereto (the “Bank Credit Agreement”). Availability under the Bank Credit Agreement is subject to a borrowing base which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations.The borrowing base is adjusted at the banks' discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months.

In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Fifth Amendment”). The Fifth Amendment extends the maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of debt to adjusted EBITDA.Under the Fifth Amendment, the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base. TheFifth Amendment also prescribes a commitment fee ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base, andadjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x.

In September 2011, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”). The Sixth Amendment permits Denbury to make distributions to its equity holders, including specifically repurchase of its common stock and/or making cash dividends with respect thereto, in an aggregate amount of up to $500 million during the term of the Credit Facility, subject to certain restrictions, including pro forma availability of no less than 25% of the borrowing base at the time of any such transactions. The Sixth Amendment provides us the flexibility to repurchase our common stock and/or pay cash dividends (within the $500 million limit) from time to time as deemed appropriate by, and subject to pre-approval of, our Board of Directors. Also in September 2011, the banks reaffirmed our borrowing base of $1.6 billion under the Bank Credit Agreement until the next scheduled redetermination in May 2012.

6⅜% Senior Subordinated Notes due 2021

In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notesbelow).

The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with theproceeds of certain equity offerings. In addition, at any time prior to August15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at aprice equal to 100% of the principal amount plus a “make-whole” premium andaccrued and unpaid interest. The indenture contains certain restrictions on ourability to incur additional debt, pay dividends on our common stock, makeinvestments, create liens on our assets, engage in transactions with ouraffiliates, transfer or sell assets, consolidate or merge, or sellsubstantially all of our assets. The 2021 Notes are not subject to any sinkingfund requirements. All of our subsidiaries, other than minor subsidiaries, fully andunconditionally guarantee this debt jointly and severally.

Redemption of our 2013 and 2015 Notes

On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 2013 Notes and all $300.0 million principal amount of our 2015 Notes. Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at104.125% of par.We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. We recognized a $16.1 million loss during the nine months ended September 30, 2011 associated with thedebt repurchases, which isincluded in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2011

Table Text Block Supplement [Abstract]

Components of Long-Term Debt

		September 30,		December 31,
In thousands		2011			2010
Bank Credit Agreement		$	110,000		$	-
7½% Senior Subordinated Notes due 2013, including discount of $437			-			224,563
7½% Senior Subordinated Notes due 2015, including premium of $427			-			300,427
9½% Senior Subordinated Notes due 2016, including premium of $12,538 and $14,589, respectively			237,458			239,509
9¾% Senior Subordinated Notes due 2016, including discount of $18,925 and $22,139, respectively			407,425			404,211
8¼% Senior Subordinated Notes due 2020			996,273			996,273
6⅜% Senior Subordinated Notes due 2021			400,000			-
Other Subordinated Notes, including premium of $35 and $41, respectively			3,841			3,848
NEJD Pipeline financing			164,626			167,331
Free State Pipeline financing			80,093			81,188
Capital lease obligations			5,010			6,806
	Total		2,404,726			2,424,156
	Less current obligations		(8,177)			(7,948)
	Long-term debt and capital lease obligations	$	2,396,549		$	2,416,208

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Supplemental Information (Details 1) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$ 137,289,000	$ 114,012,000
Cash paid for interest, capitalized	42,004,000	56,079,000
Cash paid for income taxes	36,688,000	13,691,000
Cash received for income tax refunds	21,990,000	13,525,000
Increase (decrease) in liabilities for capital expenditures	86,769,000	13,880,000
Issuance of Denbury common stock in connection with the Encore Merger	$ 0	$ 2,085,681,000

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Acquisitions and Divestitures (Details Textuals) (USD $)	3 Months Ended		6 Months Ended	9 Months Ended					1 Months Ended						1 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Mar. 31, 2010	Oct. 15, 2010 Riley Ridge [Member] Acres	May 31, 2010 Southern Assets [Member]	Aug. 31, 2010 Cleveland Sand Play [Member]	Aug. 01, 2011 Riley Ridge Phase 2 [Member]	Aug. 01, 2011 Additional Acres Surrounding Riley Ridge [Member]	Aug. 01, 2011 Riley Ridge Gas Plant [Member]	Oct. 15, 2010 Riley Ridge Gas Plant [Member]	Mar. 31, 2010 Genesis Energy LP [Member]	Feb. 28, 2010 Genesis Energy LLC [Member]
Acquisitions and Divestitures (Textuals) [Abstract]
Value of Encore Merger							$ 4,800,000,000
Revenues recognized from current period acquisitions		174,300,000	435,200,000
Transaction and other costs	0	11,470,000		4,377,000	79,253,000
Working interest in business acquisition								42.50%			57.50%	33.00%	57.50%	42.50%
Acreage adjacent to Riley Ridge								28,000
Business Acquisition, Percentage of CO2 rights in additional 28,000 acres								33.00%
Net Field Operating Income		114,100,000	294,800,000
Net proceeds from sale of interest in Genesis															79,000,000	84,000,000
Pre tax gain on sale of interest in Genesis	0	(3,000)		0	101,537,000
Gain on sale of interest in Genesis after tax					63,000,000
Net proceeds from sales of oil and natural gas properties and equipment				47,598,000	909,986,000				892,100,000	32,100,000
Contingent payment to be paid at the time the property's gas processing facility is operational and meets specific performance conditions	$ 15,000,000			$ 15,000,000		$ 0					$ 15,000,000

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Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Expenses
Interest capitalized	$ 17,853,000	$ 10,917,000	$ 42,004,000	$ 56,079,000

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value, Assets and Liabilities Measured on Recurring Basis [Abstract]

Fair value hierarchy of financial assets and liabilities

			Fair Value Measurements Using:
					Significant
			Quoted Prices		Other		Significant
			in Active		Observable		Unobservable
			Markets		Inputs		Inputs
In thousands			(Level 1)		(Level 2)		(Level 3)		Total
September 30, 2011
Assets
	Short-term investments		$	81,851	$	-	$	-	$	81,851
	Oil and natural gas derivative contracts			-		166,244		6,977		173,221
Liabilities
	Oil and natural gas derivative contracts			-		(130)		-		(130)
		Total	$	81,851	$	166,114	$	6,977	$	254,942
December 31, 2010
Assets
	Short-term investments		$	93,020	$	-	$	-	$	93,020
	Oil and natural gas derivative contracts			-		20,683		16,478		37,161
Liabilities
	Oil and natural gas derivative contracts			-		(81,162)		-		(81,162)
		Total	$	93,020	$	(60,479)	$	16,478	$	49,019

The changes in the fair value of Denbury's Level 3 assets and liabilities

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
In thousands		2011		2010		2011		2010
Balance, beginning of period		$	6,638	$	40,283	$	16,478	$	-
	Unrealized gains (losses) on commodity derivative contracts included in earnings		1,717		20,103		(5,359)		35,002
	Commodity derivative contracts acquired from Encore		-		-		-		38,093
	Receipts on settlement of commodity derivative contracts		(1,378)		(9,035)		(4,142)		(21,744)
Balance, end of period		$	6,977	$	51,351	$	6,977	$	51,351

Fair value of financial instruments that are not recorded at fair value in our Consolidated Financial Statements

		September 30, 2011				December 31, 2010
		Carrying		Estimated		Carrying		Estimated
In thousands		Amount		Fair Value		Amount		Fair Value
	7½% Senior Subordinated Notes due 2013	$	-	$	-	$	224,563	$	228,375
	7½% Senior Subordinated Notes due 2015		-		-		300,427		310,500
	9½% Senior Subordinated Notes due 2016		237,458		242,914		239,509		249,661
	9¾% Senior Subordinated Notes due 2016		407,425		460,458		404,211		475,380
	8¼% Senior Subordinated Notes due 2020		996,273		1,046,087		996,273		1,080,956
	6⅜% Senior Subordinated Notes due 2021		400,000		388,000		-		-

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Basis of Presentation (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Weighted average shares used in the basic and diluted net income per common share
Weighted average common shares - basic	399,040,000	395,913,000	398,371,000	362,241,000
Potentially dilutive securities:
Performance-Based Awards	41,000	292,000	22,000	305,000
Weighted average common shares - diluted	403,311,000	401,093,000	403,575,000	367,434,000
Stock Options and SARs [Member]
Potentially dilutive securities:
Stock options, SARs, and Restricted stock	2,954,000	3,647,000	3,818,000	3,772,000
Restricted Stock [Member]
Potentially dilutive securities:
Stock options, SARs, and Restricted stock	1,276,000	1,241,000	1,364,000	1,116,000

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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Condensed Consolidated Statements of Comprehensive Operations [Abstract]
Consolidated net income (loss)	$ 275,670,000	$ 31,234,000	$ 520,726,000	$ 281,767,000
Other comprehensive income (loss), net of income tax:
Net unrealized losses on available-for-sale securities, net of tax	(3,949,000)	0	(6,925,000)	0
Interest rate lock derivative contracts reclassified to income, net of tax	17,000	17,000	52,000	52,000
Change in deferred hedge loss on interest rate swaps, net of tax	0	(68,000)	0	(155,000)
Consolidated comprehensive income (loss)	271,738,000	31,183,000	513,853,000	281,664,000
Less: comprehensive income attributable to noncontrolling interest	0	(2,074,000)	0	(20,308,000)
Comprehensive income (loss) attributable to Denbury stockholders	$ 271,738,000	$ 29,109,000	$ 513,853,000	$ 261,356,000

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Subsequent Events

9 Months Ended

Sep. 30, 2011

Subsequent Events [Abstract]

Subsequent Events (Unaudited)

Note 8. Subsequent Event

In early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company's Board of Directors. The program has no pre-established ending date, and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for$149.3 million, or $13.58 per share under this share repurchase program.

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Derivative Instruments and Hedging Activities (Details 2) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Derivative financial instruments in Balance Sheet
Total derivatives not designated as hedging instruments	$ 163,236,000	$ (70,710,000)
Oil contracts [Member] | Derivative assets-current [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	96,177,000	3,050,000
Natural Gas Contracts [Member] | Derivative assets-current [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	20,584,000	21,192,000
Oil contracts [Member] | Derivative assets - long - term [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	52,627,000	1,301,000
Natural Gas Contracts [Member] | Derivative assets - long - term [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	3,833,000	11,618,000
Oil contracts [Member] | Derivative liabilities-current [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	60,000	55,256,000
Natural Gas Contracts [Member] | Derivative liabilities-current [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	0	0
Derivative liabilities-current [Member] | Deferred Premiums [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	9,193,000	22,928,000
Oil contracts [Member] | Derivative liabilities-long term [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	70,000	25,906,000
Natural Gas Contracts [Member] | Derivative liabilities-long term [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	0	0
Derivative liabilities-long term [Member] | Deferred Premiums [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	$ 662,000	$ 3,781,000

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities (Tables) [Abstract]

Commodity derivative expense (income), included in our Consolidated Statements of Operations

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
In thousands			2011		2010		2011		2010
Oil
	Payment on settlements of derivative contracts		$	1,857	$	3,590	$	23,857	$	80,969
	Fair value adjustments to derivative contracts - expense (income)			(205,355)		62,450		(225,485)		(144,471)
		Total derivative expense (income) - oil		(203,498)		66,040		(201,628)		(63,502)
Natural Gas
	Receipt on settlements of derivative contracts			(6,427)		(13,626)		(19,073)		(34,005)
	Fair value adjustments to derivative contracts - expense (income)			(229)		(19,933)		8,393		(39,041)
		Total derivative expense (income) - natural gas		(6,656)		(33,559)		(10,680)		(73,046)
Ineffectiveness on interest rate swaps				-		(627)		-		(1,497)
		Derivative expense (income)	$	(210,154)	$	31,854	$	(212,308)	$	(138,045)

Commodity derivative contracts not classified as hedging instruments

				NYMEX Contract Prices Per Bbl
		Type of		Weighted Average Price
Year	Months	Contract	Bbls/d	Swap		Floor		Ceiling
Oil Contracts
2011	Oct - Dec	Swap	625	$	79.18	$	-	$	-
		Collar	45,500		-		70.33		101.74
		Put	6,625		-		69.53		-
	Total Oct - Dec 2011		52,750
2012	Jan - Mar	Swap	625		81.04		-		-
		Collar	52,000		-		70.00		106.86
		Put	625		-		65.00		-
	Total Jan - Mar 2012		53,250
	Apr-June	Swap	625		81.04		-		-
		Collar	53,000		-		70.00		119.44
		Put	625		-		65.00		-
	Total Apr - June 2012		54,250
	July-Sept	Swap	625		81.04		-		-
		Collar	53,000		-		80.00		128.57
		Put	625		-		65.00		-
	Total July - Sept 2012		54,250
	Oct - Dec	Swap	625		81.04		-		-
		Collar	53,000		-		80.00		128.57
		Put	625		-		65.00		-
	Total Oct - Dec 2012		54,250
2013	Jan - Mar	Collar	16,000		-		70.00		112.66
	Total Jan - Mar 2013		16,000

			Type of		Weighted Average Swap
Year		Months	Contract	MMBtu/d	Price per MMBtu
Natural Gas Contracts
	2011	Oct - Dec	Swap	33,500	$	6.27
		Total Oct - Dec 2011		33,500
	2012	Jan - Dec	Swap	20,000		6.53
		Total Jan - Dec 2012		20,000

Derivative financial instruments in Balance Sheet

					Estimated Fair Value
					Asset (Liability)
In thousands					September 30,		December 31,
Type of Contract				Balance Sheet Location	2011		2010
Derivatives not designated as hedging instruments:
	Derivative asset
		Oil contracts		Derivative assets - current	$	96,177	$	3,050
		Natural gas contracts		Derivative assets - current		20,584		21,192
		Oil contracts		Derivative assets - long-term		52,627		1,301
		Natural gas contracts		Derivative assets - long-term		3,833		11,618
	Derivative liability
		Oil contracts		Derivative liabilities - current		(60)		(55,256)
		Deferred premiums		Derivative liabilities - current		(9,193)		(22,928)
		Oil contracts		Derivative liabilities - long-term		(70)		(25,906)
		Deferred premiums		Derivative liabilities - long-term		(662)		(3,781)
			Total derivatives not designated as hedging instruments		$	163,236	$	(70,710)

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 24,363,000	$ 381,869,000
Accrued production receivable	264,999,000	223,584,000
Trade and other receivables, net of allowance	176,734,000	114,149,000
Short-term investments	81,851,000	93,020,000
Derivative assets	116,761,000	24,242,000
Deferred tax assets	0	27,454,000
Total current assets	664,708,000	864,318,000
Oil and natural gas properties (using full cost accounting)
Proved	6,763,404,000	6,042,442,000
Unevaluated	1,088,733,000	870,130,000
CO2 and other non-hydrocarbon gases properties	599,881,000	523,423,000
Pipelines And Plant	1,598,098,000	1,378,239,000
Other property and equipment	142,243,000	120,641,000
Less accumulated depletion, depreciation, amortization, and impairment	2,510,715,000	2,197,517,000
Net property and equipment	7,681,644,000	6,737,358,000
Derivative assets	56,460,000	12,919,000
Goodwill	1,236,094,000	1,232,418,000
Other assets	248,027,000	218,050,000
Total assets	9,886,933,000	9,065,063,000
Current liabilities
Accounts payable and accrued liabilities	405,243,000	350,068,000
Oil and gas production payable	183,521,000	143,145,000
Derivative liabilities	9,253,000	78,184,000
Long-term Debt and Capital Lease Obligations, Current	8,177,000	7,948,000
Deferred Tax Liabilities, Current	37,326,000	0
Total current liabilities	643,520,000	579,345,000
Long-term liabilities
Long-term debt, net of current portion	2,396,549,000	2,416,208,000
Asset retirement obligations	87,725,000	81,290,000
Derivative liabilities	732,000	29,687,000
Deferred taxes	1,799,793,000	1,547,992,000
Other Liabilities, Noncurrent	22,842,000	29,834,000
Total long-term liabilities	4,307,641,000	4,105,011,000
Stockholders' equity
Preferred Stock, Value, Issued	0	0
Common Stock, Value, Issued	403,000	400,000
Paid-in capital in excess of par	3,085,862,000	3,045,937,000
Retained earnings	1,856,868,000	1,336,142,000
Accumulated other comprehensive income (loss)	(7,361,000)	(488,000)
Treasury stock, at cost	0	(1,284,000)
Total stockholders' equity	4,935,772,000	4,380,707,000
Total liabilities and stockholders' equity	$ 9,886,933,000	$ 9,065,063,000

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Fair Value Measurements (Details 1) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance, beginning of period	$ 6,638,000	$ 40,283,000	$ 16,478,000	$ 0
Unrealized gains on commodity derivative contracts included in net earnings	1,717,000	20,103,000	(5,359,000)	35,002,000
Commodity derivative contracts acquired from Encore	0	0	0	38,093,000
Receipts on settlement of commodity derivative contracts	(1,378,000)	(9,035,000)	(4,142,000)	(21,744,000)
Balance, end of period	$ 6,977,000	$ 51,351,000	$ 6,977,000	$ 51,351,000

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Fair Value Measurements (Details 2) (USD $)	Sep. 30, 2011	Dec. 31, 2010
7.5% Senior Subordinated Notes due 2013 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Subordinated Notes, Carrying Amount	$ 0	$ 224,563,000
Senior Subordinated Notes, Estimated Fair Value	0	228,375,000
7.5% Senior Subordinated Notes due 2015 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Subordinated Notes, Carrying Amount	0	300,427,000
Senior Subordinated Notes, Estimated Fair Value	0	310,500,000
9.5% Senior Subordinated Notes due 2016 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Subordinated Notes, Carrying Amount	237,458,000	239,509,000
Senior Subordinated Notes, Estimated Fair Value	242,914,000	249,661,000
9.75% Senior Subordinated Notes due 2016 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Subordinated Notes, Carrying Amount	407,425,000	404,211,000
Senior Subordinated Notes, Estimated Fair Value	460,458,000	475,380,000
8.25% Senior Subordinated Notes due 2020 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Subordinated Notes, Carrying Amount	996,273,000	996,273,000
Senior Subordinated Notes, Estimated Fair Value	1,046,087,000	1,080,956,000
6 3/8% Senior Subordinated Notes Due 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Subordinated Notes, Carrying Amount	400,000,000	0
Senior Subordinated Notes, Estimated Fair Value	$ 388,000,000	$ 0