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 June 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 (Do not check if a smaller reporting company) Smaller reporting company o

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 August 1, 2011
Common Stock, $.001 par value	402,350,295

DENBURY RESOURCES INC.

INDEX

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010		3
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010		5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 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		21
Item 3. Quantitative and Qualitative Disclosures about Market Risk		37
Item 4. Controls and Procedures		38
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		39
Item 1A. Risk Factors		39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 6. Exhibits		39
Signatures		40
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)

	June 30,			December 31,
	2011			2010
ASSETS
Current assets
Cash and cash equivalents	$	121,792		$	381,869
Accrued production receivable		255,034			223,584
Trade and other receivables, net of allowance of $486 and $456, respectively		153,018			114,149
Short-term investments		88,220			93,020
Derivative assets		19,322			24,242
Deferred tax assets		22,097			27,454
Total current assets		659,483			864,318
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		6,508,928			6,042,442
Unevaluated		952,452			870,130
CO2 and other non-hydrocarbon gases properties		572,957			523,423
Pipelines and plants		1,445,214			1,378,239
Other property and equipment		138,671			120,641
Less accumulated depletion, depreciation, amortization, and impairment		(2,403,741	)		(2,197,517	)
Net property and equipment		7,214,481			6,737,358
Derivative assets		17,609			12,919
Goodwill		1,232,418			1,232,418
Other assets		215,432			218,050
Total assets	$	9,339,423		$	9,065,063
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	333,953		$	345,998
Oil and gas production payable		172,837			143,145
Derivative liabilities		81,627			78,184
Current maturities of long-term debt		8,622			7,948
Other liabilities		4,070			4,070
Total current liabilities		601,109			579,345
Long-term liabilities
Long-term debt, net of current portion		2,288,112			2,416,208
Asset retirement obligations		86,109			81,290
Derivative liabilities		3,378			29,687
Deferred taxes		1,687,839			1,547,992
Other liabilities		24,562			29,834
Total long-term liabilities		4,090,000			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; 402,508,885 and 400,291,033 shares issued, respectively		403			400
Paid-in capital in excess of par		3,074,335			3,045,937
Retained earnings		1,581,198			1,336,142
Accumulated other comprehensive loss		(3,429	)		(488	)
Treasury stock, at cost, 193,177 and 78,524 shares, respectively		(4,193	)		(1,284	)
Total stockholders’ equity		4,648,314			4,380,707
Total liabilities and stockholders’ equity	$	9,339,423		$	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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Revenues and other income
Oil, natural gas, and related product sales	$	591,099		$	488,028		$	1,097,291		$	818,914
CO2 sales and transportation fees		5,343			4,690			10,267			9,187
Gain on sale of interests in Genesis		—			(28	)		—			101,540
Interest income and other income		4,955			4,520			8,004			6,390
Total revenues and other income		601,397			497,210			1,115,562			936,031
Expenses
Lease operating expenses		129,932			127,743			257,029			223,963
Production taxes and marketing expenses		39,688			38,100			72,439			57,417
CO2 discovery and operating expenses		1,869			1,681			4,023			3,049
General and administrative		30,900			31,192			74,746			63,901
Interest, net of amounts capitalized of $13,194, $23,850, $24,151 and $45,162, respectively		42,249			43,483			91,026			69,899
Depletion, depreciation, and amortization		103,495			129,209			197,089			211,081
Derivatives income		(172,904	)		(128,674	)		(2,154	)		(169,899	)
Loss on early extinguishment of debt		348			—			16,131			—
Transaction and other costs related to the Encore Merger		2,018			22,784			4,377			67,783
Total expenses		177,595			265,518			714,706			527,194
Income before income taxes		423,802			231,692			400,856			408,837
Income tax provision
Current income taxes		12,028			6,941			11,180			7,610
Deferred income taxes		152,528			74,422			144,620			150,694
Consolidated net income		259,246			150,329			245,056			250,533
Less: net income attributable to noncontrolling interest		—			(14,962	)		—			(18,278	)
Net income attributable to Denbury stockholders	$	259,246		$	135,367		$	245,056		$	232,255
Net income per common share
Basic	$	0.65		$	0.34		$	0.62		$	0.67
Diluted	$	0.64		$	0.34		$	0.61		$	0.66
Weighted average common shares outstanding
Basic		398,631			395,548			398,032			345,126
Diluted		403,919			400,867			403,703			350,326

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)

	Six Months Ended
	June 30,
	2011			2010
Cash flows from operating activities
Consolidated net income	$	245,056		$	250,533
Adjustments needed to reconcile to net cash provided by operating activities
Depletion, depreciation, and amortization		197,089			211,081
Deferred income taxes		144,620			150,694
Gain on sale of interests in Genesis		—			(101,540	)
Stock-based compensation		18,132			17,130
Non-cash fair value derivative adjustments		(11,508	)		(226,899	)
Loss on early extinguishment of debt		16,131			—
Other, net		5,755			5,871
Changes in operating assets and liabilities
Accrued production receivable		(35,068	)		52,075
Trade and other receivables		(28,258	)		10,058
Other assets		(2,920	)		(3,134	)
Accounts payable and accrued liabilities		(48,471	)		12,066
Oil and natural gas production payable		30,135			11,236
Other liabilities		(7,340	)		(4,880	)
Net cash provided by operating activities		523,353			384,291
Cash flows used for investing activities
Oil and natural gas capital expenditures		(471,601	)		(317,173	)
Acquisitions of oil and natural gas properties		(32,482	)		(24,243	)
Cash paid in Encore Merger, net of cash acquired		—			(801,489	)
CO2 and other non-hydrocarbon gases capital expenditures		(31,731	)		(44,274	)
Pipelines and plants capital expenditures		(98,669	)		(108,177	)
Net proceeds from sales of oil and natural gas properties and equipment		—			881,344
Net proceeds from sale of interests in Genesis		—			162,622
Other		1,643			(7,224	)
Net cash used for investing activities		(632,840	)		(258,614	)
Cash flows from financing activities
Bank repayments		(130,000	)		(1,514,000	)
Bank borrowings		130,000			1,149,000
Repayment of senior subordinated notes		(525,000	)		(609,424	)
Premium paid on repayment of senior subordinated notes		(13,137	)		(7,214	)
Net proceeds from issuance of senior subordinated notes		400,000			1,000,000
Net proceeds from issuance of common stock		9,203			5,540
Costs of debt financing		(13,274	)		(76,232	)
ENP distributions to noncontrolling interest		—			(12,209	)
Other		(8,382	)		(14,255	)
Net cash used for financing activities		(150,590	)		(78,794	)
Net increase (decrease) in cash and cash equivalents		(260,077	)		46,883
Cash and cash equivalents at beginning of period		381,869			20,591
Cash and cash equivalents at end of period	$	121,792		$	67,474

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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Consolidated net income	$	259,246		$	150,329		$	245,056		$	250,533
Other comprehensive income, net of income tax
Net unrealized loss on available-for-sale securities, net of tax of $(4,375) and $(1,824), respectively		(7,139	)		—			(2,976	)		—
Interest rate lock derivative contracts reclassified to income, net of tax of $10, $10, $21, and $21, respectively		18			17			35			34
Change in deferred hedge loss on interest rate swaps, net of tax of $8 and $18, respectively		—			(60	)		—			(87	)
Consolidated comprehensive income		252,125			150,286			242,115			250,480
Less: comprehensive income attributable to noncontrolling interest		—			(14,950	)		—			(18,235	)
Comprehensive income attributable to Denbury stockholders	$	252,125		$	135,336		$	242,115		$	232,245

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 June 30, 2011, our consolidated results of operations for the three and six months ended June 30, 2011 and 2010, and our consolidated cash flows for the six months ended June 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 Sheets as of December 31, 2010 and June 30, 2011, nor do our Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 or our Unaudited Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2011 include ENP’s results of operations or cash flows. As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010, “Net income attributable to noncontrolling interest” of $15.0 million and $18.3 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 six months ended June 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				Six Months Ended
	June 30,				June 30,
In thousands	2011		2010		2011		2010
Basic weighted average common shares		398,631		395,548		398,032		345,126
Potentially dilutive securities:
Stock options and SARs		3,946		3,980		4,251		3,835
Performance equity awards		23		146		12		312
Restricted stock		1,319		1,193		1,408		1,053
Diluted weighted average common shares		403,919		400,867		403,703		350,326

     Basic weighted average common shares excludes 3.4 million and 3.6 million shares for the three and six months ended ended June 30, 2011, respectively, and 3.5 million and 3.3 million shares for the three and six months ended June 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				Six Months Ended
	June 30,				June 30,
In thousands	2011		2010		2011		2010
Stock options and SARs		2,412		4,223		2,297		4,785
Restricted stock		24		35		15		413

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 June 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 $1.7 million and $3.5 million on the Vanguard common units we own for the three and six months ended June 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 $7.1 million (net of a tax benefit of $4.4 million) and $3.0 million (net of a tax benefit of $1.8 million) for the three and six months ended June 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Recently Issued Accounting Pronouncements

     In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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

     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.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Acquisitions and Divestitures

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 June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $200.6 million and $260.9 million, respectively, of oil, natural gas sales and related product sales related to the Encore Merger. For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $137.8 million and $180.7 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) related to the Encore Merger. We recognized a total of $2.0 million and $22.8 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 June 30, 2011 and 2010, respectively, and $4.4 million and $67.8 million of such costs for the six months ended June 30, 2011 and 2010, respectively.

2010 Acquisition 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 working interest in a gas plant, which is 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.

     This acquisition meets the definition of a business under the FASC Business Combinations topic. The following table presents a summary of the preliminary fair value of these Riley Ridge assets acquired and liabilities assumed:

In thousands
Oil and natural gas properties	$	19,646
CO2 and other non-hydrocarbon gases properties		10,907
Pipelines and plants		72,070
Prepaid construction and drilling costs		9,346
Other assets		19,300
Asset retirement obligations		(472	)
Goodwill		1,460
Total	$	132,257

     On August 1, 2011, we acquired the remaining working interest in Riley Ridge and an additional interest in the adjoining acreage and became the operator of both projects; see Note 8, Subsequent Event, for more information.

Pro Forma Information

     Had the Encore Merger and October 2010 Riley Ridge acquisition both occurred on January 1, 2010, our combined pro forma revenues and net income for the three and six months ended June 30, 2010, would have been as follows:

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

	Pro Forma Results
	Three Months Ended		Six Months Ended
In thousands, except per share amounts	June 30, 2010		June 30, 2010
Pro forma total revenues	$	497,210	$	1,112,481
Pro forma net income attributable to Denbury stockholders		135,494		247,423
Pro forma net income per common share:
Basic	$	0.34	$	0.63
Diluted		0.34		0.62

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 Sale of Southern Assets

     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. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

Note 3. Long-Term Debt

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

	June 30,			December 31,
In thousands	2011			2010
Bank Credit Agreement	$	—		$	—
71/2% Senior Subordinated Notes due 2013, including discount of $437		—			224,563
71/2% Senior Subordinated Notes due 2015, including premium of $427		—			300,427
91/2% Senior Subordinated Notes due 2016, including premium of $13,222 and $14,589, respectively		238,142			239,509
93/4% Senior Subordinated Notes due 2016, including discount of $19,996 and $22,139, respectively		406,354			404,211
81/4% Senior Subordinated Notes due 2020		996,273			996,273
6⅜% Senior Subordinated Notes due 2021		400,000			—
Other Subordinated Notes, including premium of $37 and $41, respectively		3,842			3,848
NEJD financing		165,550			167,331
Free State financing		80,953			81,188
Capital lease obligations		5,620			6,806
Total		2,296,734			2,424,156
Less current obligations		(8,622	)		(7,948	)
Long-term debt and capital lease obligations	$	2,288,112		$	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. All of our 100% owned subsidiaries, other than minor subsidiaries, 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.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Amendment”). The Amendment reconfirms our current borrowing base of $1.6 billion, 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 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 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, and adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x.

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.

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 $0.3 million and $16.1 million loss during the three and six months ended June 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 and Hedging Activities

Oil and Natural Gas Derivative Contracts

     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.

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Notes to Unaudited Condensed Consolidated Financial Statements

     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						Six Months Ended
	June 30,						June 30,
In thousands	2011			2010			2011			2010
Oil
Payment on settlements of derivative contracts	$	16,972		$	13,829		$	22,000		$	77,379
Fair value adjustments to derivative contracts — expense (income)		(187,194	)		(145,099	)		(20,130	)		(206,920	)
Total derivative expense (income) — oil		(170,222	)		(131,270	)		1,870			(129,541	)
Natural Gas
Receipt on settlements of derivative contracts		(6,030	)		(16,630	)		(12,646	)		(20,379	)
Fair value adjustments to derivative contracts — expense (income)		3,348			19,909			8,622			(19,109	)
Total derivative expense (income) — natural gas		(2,682	)		3,279			(4,024	)		(39,488	)
Ineffectiveness on interest rate swaps		—			(683	)		—			(870	)
Derivative income	$	(172,904	)	$	(128,674	)	$	(2,154	)	$	(169,899	)

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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 June 30, 2011:

					NYMEX Contract Prices Per Bbl
		Type of					Weighted Average Price
Year	Months	Contract	Bbls/d		Swap		Floor		Ceiling
Oil Contracts
2011	July - Sept	Swap		625		79.18		—		—
		Collar		42,500		—		70.35		100.09
		Put		6,625		—		69.53		—
		Total July - Sept 2011		49,750
	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

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Notes to Unaudited Condensed Consolidated Financial Statements

		Type of			Weighted Average Swap
Year	Months	Contract	MMBtu/d		Price per MMBtu
Natural Gas Contracts
2011	July - Sept	Swap		33,500	$	6.27
		Total July-Sept 2011		33,500
	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 June 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)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2011			2010
		(In thousands)
Derivatives not designated as hedging instruments
Derivative asset
Oil contracts	Derivative assets — current	$	1,462		$	3,050
Natural gas contracts	Derivative assets — current		17,860			21,192
Oil contracts	Derivative assets — long-term		11,281			1,301
Natural gas contracts	Derivative assets — long-term		6,328			11,618
Derivative liability
Oil contracts	Derivative liabilities — current		(67,196	)		(55,256	)
Deferred premiums	Derivative liabilities — current		(14,431	)		(22,928	)
Oil contracts	Derivative liabilities — long-term		(2,228	)		(25,906	)
Deferred premiums	Derivative liabilities — long-term		(1,150	)		(3,781	)
Total derivatives not designated as hedging instruments		$	(48,074	)	$	(70,710	)

Note 5. Fair Value Measurements

Fair Value Hierarchy

     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:

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Notes to Unaudited Condensed Consolidated Financial Statements

• 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
June 30, 2011
Assets
Short-term investments	$	88,220	$	—		$	—	$	88,220
Oil and natural gas derivative contracts		—		30,293			6,638		36,931
Liabilities
Oil and natural gas derivative contracts		—		(69,424	)		—		(69,424	)
Total	$	88,220	$	(39,131	)	$	6,638	$	55,727
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

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Notes to Unaudited Condensed Consolidated Financial Statements

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands	2011			2010			2011			2010
Balance, beginning of period	$	15,346		$	50,518		$	16,478		$	—
Unrealized gains/(losses) on commodity derivative contracts included in earnings		(7,386	)		126			(7,076	)		14,899
Commodity derivative contracts acquired from Encore		—			—			—			38,093
Receipts on settlement of commodity derivative contracts		(1,322	)		(10,361	)		(2,764	)		(12,709	)
Balance, end of period		6,638			40,283		$	6,638		$	40,283

     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 income” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

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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:

	June 30, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
In thousands	Amount		Fair Value		Amount		Fair Value
71/2% Senior Subordinated Notes due 2013	$	—	$	—	$	224,563	$	228,375
71/2% Senior Subordinated Notes due 2015		—		—		300,427		310,500
91/2% Senior Subordinated Notes due 2016		238,142		249,942		239,509		249,661
93/4% Senior Subordinated Notes due 2016		406,354		476,446		404,211		475,380
81/4% Senior Subordinated Notes due 2020		996,273		1,085,938		996,273		1,080,956
6⅜% Senior Subordinated Notes due 2021		400,000		400,000		—		—

     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 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:

	June 30,		December 31,
In thousands	2011		2010
Accounts payable	$	72,830	$	47,660
Accrued exploration and development costs		96,910		101,758
Accrued compensation		26,760		39,757
Accrued lease operating expense		25,100		23,557
Accrued interest		61,166		57,077
Taxes payable		16,537		34,371
Other		34,650		41,818
Total	$	333,953	$	345,998

Supplemental Cash Flow Information

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

	Six Months Ended
	June 30,
In thousands	2011		2010
Cash paid for interest, expensed	$	72,774	$	43,296
Cash paid for interest, capitalized		24,151		45,162
Cash paid for income taxes		31,072		11,920
Cash received for income tax refunds		20,841		13,093
Increase in liabilities for capital expenditures		25,141		46,170
Issuance of Denbury common stock in connection with the Encore Merger		—		2,085,681

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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 in Medicine Bow, Wyoming, purchase 70% of the CO₂ captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) 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 200 MMCF/d of CO₂ from the MBFP project in 2015, 115 MMcf/d of CO₂ from the IGCC 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 IGCC and Air Products plants are currently being constructed and MBFP is in the initial stages of construction but its completion is still contingent upon securing debt financing and equity commitments and receipt of all necessary consents and approvals.

     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. We have received a $15.0 million assessment from the Mississippi taxing authority for use tax, penalties and interest covering the 2004-2007 period. We believe this assessment is significantly in excess of any amounts owed and we are appealing the assessment. We do not believe the outcome of this matter will have a material adverse effect on our financial position or results of operations.

     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

     On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge 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 $191 million, including a $15 million contingent payment to be paid at the time the property’s gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments including payment for capital expenditures incurred between the effective date of the purchase (April 1, 2011) and closing. We expect the gas processing facility to be operational during the fourth quarter of 2011.

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Notes to Unaudited Condensed Consolidated Financial Statements

     The acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. We will account for our acquisition of Riley Ridge under the acquisition method of accounting, which will result in the allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition, with the excess purchase price, if any, being recognized as goodwill. We have not yet completed our initial calculation necessary to make this allocation.

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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 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 for the first six months of 2010 to those in the first six months of 2011, which is more fully detailed throughout the following discussion and analysis. Our financial results for the first six months of 2010 include the results of operations of Encore from the date of the acquisition on March 9, 2010 through June 30, 2010. Additionally, starting in May 2010 and throughout the remainder of that year, we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).

     Second Quarter Operating Highlights. We recognized net income of $259.2 million, or $0.65 per basic common share, during the second quarter of 2011 as compared to net income of $135.4 million, or $0.34 per basic common share, during the second quarter of 2010. This increase between the two periods is primarily attributable to:

• A $103.1 million ($63.9 million after tax), or 21%, increase in revenue, made up of $214.4 million of additional revenue from higher realized commodity prices in the 2011 second quarter, partially offset by a decrease of $111.3 million of revenue primarily attributable to the absence in the most recent quarter of production from properties sold starting in May 2010;

• A $58.6 million increase in the non-cash fair value adjustment in the mark-to-market valuation of our commodities derivatives, principally attributable to oil futures (non-cash income of $183.8 million in the second quarter of 2011 compared to $125.2 million of such non-cash income in the second quarter of 2010); and

• $22.8 million of transaction and other costs related to the Encore Merger incurred in the 2010 period ($14.1 million after tax), which costs were negligible in the most recent quarter.

     During the second quarter of 2011, our oil and natural gas production, which was 92% oil, averaged 64,919 BOE/d compared to 84,111 BOE/d produced during the second quarter of 2010. This drop in production is primarily attributable to the sale of non-strategic legacy Encore assets and our interests in ENP (which together had production of 20,526 BOE/d in last year’s second quarter), which were sold starting in May 2010, partially offset by increases in our quarterly tertiary and Bakken production. Our tertiary oil production averaged 30,771 Bbls/d during the second quarter of 2011, up 8% over the 28,507 Bbls/d during the second quarter a year earlier. Tertiary oil production was essentially flat sequentially (down 0.2%, or 54 Bbls/d) for the second quarter. Our Bakken oil production averaged 7,626 BOE/d during the second quarter of 2011, up 69% over production of 4,500 BOE/d during the second quarter of 2010 and sequentially up 33% from levels in the first quarter of 2011. See Results of Operations — CO₂ Operations and Results of Operations — Operating Results — Production for more information.

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

     Oil prices during the second quarter of 2011 were considerably higher than prices during the second quarter of 2010. Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $100.06 per BOE during the second quarter of 2011, compared to $63.76 per BOE during the second quarter of 2010, a 57% increase between the two periods. Including the impact of cash settlements on our commodity derivative contracts, our average oil and natural gas price per BOE was $98.21 per BOE during the second quarter of 2011 compared to $64.13 per BOE during the second quarter of 2010, a 53% increase. During the second quarter of 2011, our oil price differentials (our received net oil price compared to NYMEX West Texas Intermediate (“WTI”) prices) improved significantly from a negative $4.13 per Bbl in the second quarter of 2010 to a positive $3.72 per Bbl in the second quarter of 2011, primarily due to the favorable price differential for 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 in the Riley Ridge Federal Unit (“Riley Ridge”) 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 $191 million, which includes a $15 million contingent payment to be paid at the time the property’s gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments, including payments for capital expenditures incurred between the effective date of the purchase (April 1, 2011) and closing. We currently expect the gas processing facility to be operational with the first production of natural gas and helium from Riley Ridge during the fourth quarter of 2011. The CO₂ will be re-injected into the reservoir until we have completed an additional separation facility and a CO₂ pipeline to the field, which is expected to be completed in four or five years.

      Combining this acquisition with the interest in Riley Ridge that we acquired in October 2010, we estimate that our total ownership at Riley Ridge currently contains estimated proved reserves of 435 Bcf of natural gas, 15.5 Bcf of helium and 2.4 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. The first production of natural gas and helium from Riley Ridge is expected to begin late in the fourth quarter of 2011, with initial production of CO₂ expected in four to five years following construction of both additional facilities to separate the CO₂ from the remaining gas stream, and a CO₂ pipeline to the field.

     Addition of Proved Oil and Natural Gas Reserves. We added 30.9 MMBOE of estimated proved reserves during the first six months. These reserve additions include 28.1 MMBOE of estimated proved reserves at our Bakken properties, and minor revisions to our other properties. These additions do not include estimated proved reserves of approximately 250 Bcf of natural gas (41.7 MMBOE) associated with the Riley Ridge acquisitions completed in August discussed above.

     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 (“MBFP”) project in Medicine Bow, Wyoming, 70% of the CO₂ captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and 100% of the CO₂ captured 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 200 MMCF/d of CO₂ from the MBFP project in 2015, 115 MMcf/d of CO₂ from the IGCC 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. Construction on the IGCC and MBFP plants is in the initial stages and additional construction under the MBFP agreement is contingent upon securing debt financing and equity commitments and receipt of all necessary consents and approvals. The Air Products agreement is also contingent upon third party approvals for the necessary utilities and infrastructure.

22

DENBURY RESOURCES INC.

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

     February 2011 Debt 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 three and six months ended June 30, 2011, we recognized $0.3 million and $16.1 million, respectively, of loss associated with the debt repurchases, included in our income statements under the caption “Loss on early extinguishment of debt”.

Capital Resources and Liquidity

     In June 2011, when we signed the agreement to acquire the remaining interest in Riley Ridge, which closed in August 2011, our Board of Directors approved a $50 million increase in our 2011 capital spending budget for development of the Riley Ridge plant, increasing our projected 2011 oil and gas capital investments to $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:

• $450 million allocated for tertiary oil field expenditures;

• $350 million in the Bakken area of North Dakota;

• $250 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

• $100 million on drilling, completion and other development activities in our other areas.

     Based on oil and natural gas commodity futures prices in early August 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is $150 million to $250 million greater than our anticipated cash flow from operations. These expenditures will be funded with our excess cash on hand or, if necessary, borrowings under our $1.6 billion Bank Credit Agreement under which at August 4, 2011, we had drawn $125 million, all of which was used as part of the funding of our August 1, 2011 Riley Ridge acquisition discussed above. Another potential source of funds would be proceeds if we should sell the units in Vanguard Natural Resources LLP units acquired in the sale of ENP, which have ranged in value between approximately $80 million and $100 million during the second quarter of 2011.

     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, we have approximately $1.4 billion of unused liquidity under our bank credit line and have significant oil price floors through the end of 2012 (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 August 1, 2011, we have funded approximately $27 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.

23

DENBURY RESOURCES INC.

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

     In May 2011, we entered into our Fifth Amendment to the Bank Credit Agreement, reconfirming our current borrowing base of $1.6 billion, extending the maturity from March 2014 to May 2016, reducing certain margins and letter of credit fees, and adjusting the maximum permitted ratio of debt to adjusted EBITDA. See further discussion in Note 3 to the Unaudited Condensed Consolidated Financial Statements.

     Capital Expenditure Summary. The following table of capital expenditures includes accrued capital for the six month periods of 2011 and 2010:

	Six Months Ended
	June 30,
In thousands	2011		2010
Oil and natural gas exploration and development:
Drilling	$	244,466	$	155,503
Geological, geophysical, and acreage		14,339		15,121
Facilities		123,742		73,712
Recompletions		104,878		91,534
Capitalized interest		18,652		13,681
Total oil and natural gas exploration and development expenditures		506,077		349,551
CO2 and other non-hydrocarbon gases capital expenditures:
Drilling		28,768		27,113
Geological, geophysical, and acreage		10,195		4,299
Facilities		13,737		12,245
Total CO2 and other non-hydrocarbon gases capital expenditures		52,700		43,657
Pipelines and plants capital expenditures:
Pipelines and plants		61,292		92,500
Capitalized interest		5,499		31,481
Total pipelines and plants capital expenditures		66,791		123,981
Total capital expenditures excluding acquisitions		625,568		517,189
Oil and natural gas property acquisitions		32,482		24,243
Consideration for the Encore Merger(1)		—		2,952,515
Total	$	658,050	$	3,493,947

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

     Our capital expenditures for the first six months of 2011 were funded with $523.4 million of cash flow from operations and the remainder with cash on hand at the beginning of the period. Our capital expenditures for the first six months of 2010, excluding the Encore Merger, were funded with $384.3 million of cash flow from operations along with proceeds from the sale of our interests in Genesis and 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 $93 million, with $9 million expected to be paid during the remainder of 2011, $31 million in both 2012 and 2013, and $22 million in 2014.

24

DENBURY RESOURCES INC.

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

     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 our 2010 Form 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.

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 second quarter of 2011, our CO₂ production at Jackson Dome averaged 992 MMcf/d compared to an average of 768 MMcf/d produced during the second quarter of 2010 and 1,021 MMcf/d produced during the first quarter of 2011. We used 91% of this production, or 903 MMcf/d, in our tertiary operations during the second 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. Even with this downward revision, we still anticipate 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.

     We spent approximately $0.27 per Mcf in operating expenses to produce our CO₂ during the first six months of 2011, comprised of $0.25 per Mcf during the first quarter of 2011 and $0.28 per Mcf during the second quarter of 2011. This rate is up significantly from our $0.22 per Mcf cost during the second quarter of 2010, due primarily to increased CO₂ royalty expense as a result of higher oil prices (to which CO₂ royalties are tied).

25

DENBURY RESOURCES INC.

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

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

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

     Oil production from our tertiary operations increased to an average of 30,771 Bbls/d during the second quarter of 2011, an 8% increase over our second quarter of 2010 tertiary production level of 28,507 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods in the Tinsley, Heidelberg and Delhi Fields. 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 varies 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 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 in the first quarter of 2011, two of our fields which have exhibited strong production growth in recent periods. These fields resumed their growth during the second quarter of 2011 and these temporary fluctuations have not changed our overall outlook for these fields.

     We initiated CO₂ injections at Oyster Bayou and Hastings Fields during June 2010 and December 2010, respectively. We currently anticipate tertiary production responses at Hastings Field in late 2011, assuming our CO₂ recycle facilities at this field are completed on schedule. We anticipate first production at Oyster Bayou Field late in the first quarter of 2012, also dependant on the completion of CO₂ recycle facilities.

     During the second quarter of 2011, operating costs for our tertiary properties averaged $23.35 per Bbl, down 8% from our first quarter 2011 average of $25.40 per Bbl, due primarily to lower workover expenses between the respective periods, but 9% higher than our second quarter 2010 average cost of $21.37 per Bbl, due primarily to higher utility and CO₂ costs. CO₂ costs increased due to a 37% increase in injection volumes, primarily related to the ramping up of tertiary activity at our Heidelberg, Tinsley and Delhi fields, and a 27% increase in the cost of CO₂ (which is variable and partially tied to oil prices). On a per Bbl basis, our cost of CO₂ increased from $5.05 per Bbl during the second quarter of 2010 to $5.62 per Bbl during the second quarter of 2011 but remained relatively consistent with the $5.58 per Bbl level of these costs during the first quarter of 2011. Second quarter of 2011 workover expenses of $2.53 per Bbl also increased from second quarter of 2010 workover expenses of $1.62 per Bbl but decreased from first quarter of 2011 levels of $3.75 per Bbl as we completed planned mechanical integrity test repairs at Brookhaven Field and completed other workovers at Soso and Eucutta during the first quarter of 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.

26

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 second quarters and first six months of 2011 and 2010 are included in the following table:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
In thousands, except per share and unit data	2011			2010(1)		2011			2010(1)
Operating results:
Net income attributable to Denbury stockholders	$	259,246		$	135,367	$	245,056		$	232,255
Net income per common share — basic		0.65			0.34		0.62			0.67
Net income per common share — diluted		0.64			0.34		0.61			0.66
Cash flow from operations		398,521			271,123		523,353			384,291
Average daily production volumes:
Bbls/d		59,538			65,942		59,002			55,185
Mcf/d		32,283			109,014		31,579			81,108
BOE/d		64,919			84,111		64,265			68,703
Operating revenues:
Oil sales	$	575,928		$	443,984	$	1,068,766		$	749,188
Natural gas sales		15,171			44,044		28,525			69,726
Total oil and natural gas sales	$	591,099		$	488,028	$	1,097,291		$	818,914
Commodity derivative contracts: (2)
Net cash receipts (payments) on settlement of commodity derivative contracts	$	(10,942	)	$	2,801	$	(9,354	)	$	(57,000	)
Non-cash fair value adjustment income		183,846			125,190		11,508			226,029
Total income from commodity derivative contracts	$	172,904		$	127,991	$	2,154		$	169,029
Operating expenses:
Lease operating	$	129,932		$	127,743	$	257,029		$	223,963
Production taxes and marketing		39,688			38,100		72,439			57,417
Total production expenses	$	169,620		$	165,843	$	329,468		$	281,380
Unit prices — including impact of derivative settlements: (2)
Oil price per Bbl	$	103.17		$	71.68	$	98.02		$	67.26
Natural gas price per Mcf		7.22			6.12		7.20			6.14
Unit prices — excluding impact of derivative settlements: (2)
Oil price per Bbl	$	106.30		$	73.99	$	100.08		$	75.00
Natural gas price per Mcf		5.16			4.44		4.99			4.75
Oil and natural gas operating revenues and expenses per BOE:
Oil and natural gas revenues	$	100.06		$	63.76	$	94.33		$	65.85
Oil and natural gas lease operating expenses	$	21.99		$	16.69	$	22.10		$	18.01
Oil and natural gas production taxes and marketing expense		6.72			4.98		6.23			4.62
Total oil and natural gas production expenses	$	28.71		$	21.67	$	28.33		$	22.63

(1)	Includes the results of operations of Encore properties and ENP from March 9, 2010 through the end of the period.
(2)	See Item 3, Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts.

27

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 and second quarters of 2011 are shown below:

	Average Daily Production (BOE/d)
	First		Pro Forma		Second		Third		Fourth		First		Second
	Quarter		First Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Operating Area	2010(1)		2010(2)		2010		2010		2010		2011		2011
Gulf Coast Region:
Tertiary oil fields		27,023		27,023		28,507		29,531		31,139		30,825		30,771
Non-tertiary fields:
Mississippi		7,829		7,829		8,967		7,965		7,293		7,586		7,333
Texas		5,235		5,235		5,148		4,824		4,564		4,371		4,202
Louisiana		662		662		775		714		687		767		659
Alabama and other		997		997		1,078		1,091		1,026		1,026		1,084
Total Gulf Coast Region		41,746		41,746		44,475		44,125		44,709		44,575		44,049
Rocky Mountain Region:
Cedar Creek Anticline		2,537		9,830		9,967		9,791		9,328		9,163		8,925
Bakken		890		3,549		4,500		4,657		5,193		5,728		7,626
Bell Creek		252		966		997		994		957		890		936
Paradox		173		675		702		738		716		635		690
Other		777		2,925		2,944		2,889		2,809		2,613		2,693
Total Rocky Mountain Region		4,629		17,945		19,110		19,069		19,003		19,029		20,870
Total Continuing Production		46,375		59,691		63,585		63,194		63,712		63,604		64,919
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

(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 June 30, 2011 increased 1,334 BOE/d over the comparable 2010 production levels, and continuing production when including Encore’s pre-merger production increased from 61,649 BOE/d during the first half of 2010 to 64,265 BOE/d during the first half 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. Additionally, our production from the Cedar Creek Anticline generally declines in periods of increasing prices due to a net profits interest associated with this production. Total production decreased 23% between the second quarters of 2010 and 2011 due to the sale of non-strategic legacy Encore properties during May 2010 through December 2010, as well as the sale of our interests in ENP in December 2010. On a year-to-date basis, total production decreased 6% between the first six months of 2010 and 2011 due primarily to the sale of the non-strategic Encore assets during 2010.

     Production from our Bakken properties averaged 7,626 BOE/d in the second quarter of 2011, a 69% increase from second quarter 2010 levels and an increase of over 33% compared to first quarter 2011 production levels. The production increases in the Bakken are due to a gradual 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 operated rigs currently. We anticipate adding a sixth rig late in the third quarter or early fourth quarter of 2011 to test our acreage in the Almond area, and a seventh rig by the end of 2011. During the first six months of 2011, we drilled and completed 16 operated wells in the Bakken. Our Bakken production for the first six months of 2011 was negatively impacted by severe winter weather and flooding which caused delays in well completions and curtailments in oil production.

28

DENBURY RESOURCES INC.

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

     Our production during both the three and six months ended June 30, 2011 was 92% oil, as compared to 78% and 80%, during the three and six months ended June 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.

     Oil and Natural Gas Revenues. Although our production for the three and six months ended June 30, 2011 declined from comparable 2010 levels due to the asset sales discussed above (partially offset during the six-month period by lower production in 2010 prior to the Encore Merger which closed in March 2010), 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 June 30,						Six Months Ended June 30,
	2011 vs. 2010						2011 vs. 2010
				Percentage						Percentage
	Increase			Increase						Increase
	(Decrease) in			(Decrease) in			Increase (Decrease)			(Decrease) in
In thousands	Revenues			Revenues			in Revenues			Revenues
Change in oil and natural gas revenues due to:
Increase in commodity prices	$	214,398			44	%	$	331,259			40	%
Decrease in production		(111,327	)		(23	%)		(52,882	)		(6	%)
Total increase in oil and natural gas revenues	$	103,071			21	%	$	278,377			34	%

     Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first and second quarters and first six month periods of 2011 and 2010:

	Three Months Ended						Three Months Ended					Six Months Ended
	March 31,						June 30,					June 30,
	2011			2010			2011		2010			2011		2010
Net Realized Prices:
Oil price per Bbl	$	93.67		$	76.53		$	106.30	$	73.99		$	100.08	$	75.00
Natural gas price per Mcf		4.81			5.40			5.16		4.44			4.99		4.75
Price per BOE		88.42			69.21			100.06		63.76			94.33		65.85
NYMEX Differentials:
Oil per Bbl	$	(0.59	)	$	(2.08	)	$	3.72	$	(4.13	)	$	1.64	$	(3.36	)
Natural gas per Mcf		0.61			0.37			0.78		0.09			0.70		0.06

     During the second quarter of 2011, our oil price differentials improved significantly, primarily due to the favorable price differential for crude oil sold under LLS index pricing. Company-wide oil price differentials in the second quarter of 2011 were $3.72 per Bbl above NYMEX, as compared to an average negative differential of $4.13 per Bbl below NYMEX in the second quarter of 2010 and an average negative differential of $0.59 per Bbl during the first quarter of 2011. Our oil price differential in the second quarter of 2010 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, the LLS index price increased significantly more than NYMEX prices, causing the LLS differential to increase significantly, and it remained high throughout the second quarter. For the second quarter of 2011, this LLS differential averaged a positive $15.32 per barrel on a trade-month basis, as compared to a $9.28 positive differential in the first quarter of 2011 and a more typical $3.21 positive differential in

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

the second 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) 40% of our crude oil based on the LLS index price, although due to contract provisions we may not realize the full differential; (b) approximately 40% based on WTI prices; and (c) approximately 20% based on various other indexes, most of which 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 six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,
	2011			2010			2011			2010			2011			2010
	Oil						Natural Gas
In thousands	Derivative Contracts						Derivative Contracts						Total Commodity Derivative Contracts
Non-cash fair value gain (loss)	$	187,194		$	145,099		$	(3,348	)	$	(19,909	)	$	183,846		$	125,190
Cash settlement receipts (payments)		(16,972	)		(13,829	)		6,030			16,630			(10,942	)		2,801
Total	$	170,222		$	131,270		$	2,682		$	(3,279	)	$	172,904		$	127,991

	Six Months Ended June 30,
	2011			2010			2011			2010		2011			2010
	Oil						Natural Gas
In thousands	Derivative Contracts						Derivative Contracts					Total Commodity Derivative Contracts
Non-cash fair value gain (loss)	$	20,130			206,920			(8,622	)		19,109	$	11,508		$	226,029
Cash settlement receipts (payments)		(22,000	)		(77,379	)		12,646			20,379		(9,354	)		(57,000	)
Total	$	(1,870	)	$	129,541		$	4,024		$	39,488	$	2,154		$	169,029

     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.

     Production Expenses. Our lease operating expenses increased 2% during the three months ended June 30, 2011 compared to the same period in 2010 primarily as a result of the increased CO₂ injections as we continued to ramp up tertiary activities at Tinsley, Heidelberg and Delhi fields during 2010 and 2011, the cost of CO₂ (which are variable and partially tied to oil prices) and workover expenses on our tertiary operations (see discussion of those expenses under CO₂ Operations), offset by the sale of the non-strategic legacy Encore and ENP properties during 2010.

     The 15% increase in lease operating expense during the six months ended June 30, 2011 compared to 2010 was further impacted by the inclusion in the 2011 period of a full six months of lease operating expense related to properties acquired in the Encore Merger on March 9, 2010.

     Lease operating expense per BOE averaged $21.99 per BOE and $22.10 per BOE for the three and six months ended June 30, 2011, compared to $16.69 per BOE and $18.01 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 generally had a lower operating cost per BOE than Denbury’s legacy properties. However, second quarter 2011 lease operating expenses per BOE decreased from $22.20 per BOE in the first quarter of 2011. Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $23.35 per BOE and $24.37 per BOE during the three and six months ended June 30, 2011, compared to $21.37 per BOE and $22.00 per BOE for the same periods in 2010. See CO₂ Operations for a more detailed discussion.

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DENBURY RESOURCES INC.

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

     Generally, production taxes change in relation to oil and natural gas revenues, and marketing expenses change in relation to production volumes. The 21% increase in oil and natural gas revenues between the second quarters of 2010 and 2011 contributed to severance taxes increasing from $28.7 to $33.4 million, respectively. Likewise, the 34% increase in oil and natural gas revenues between the first six months of 2010 and 2011 contributed to severance taxes increasing from $43.6 million to $60.9 million, respectively. 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						Six Months Ended
	June 30,						June 30,
In thousands, except per BOE data and employees	2011			2010			2011			2010
Gross cash G&A expense	$	60,137		$	57,909		$	127,834		$	106,183
Gross stock-based compensation		9,687			7,363			21,024			17,302
State franchise taxes		1,668			965			2,827			2,035
Operator labor and overhead recovery charges		(31,423	)		(29,086	)		(61,139	)		(51,131	)
Capitalized exploration and development costs		(9,169	)		(5,959	)		(15,800	)		(10,488	)
Net G&A expense	$	30,900		$	31,192		$	74,746		$	63,901
G&A per BOE:
Net cash G&A expense	$	3.73		$	3.15		$	4.78		$	3.81
Net stock-based compensation		1.22			0.79			1.41			1.17
State franchise taxes		0.28			0.13			0.24			0.16
Net G&A expense	$	5.23		$	4.07		$	6.43		$	5.14
Employees as of June 30		1,283			1,304			1,283			1,304

     Gross cash G&A expenses increased $2.2 million (4%) and $21.7 million (20%) during the three and six months ended June 30, 2011, respectively, as compared to the same periods of 2010. The increase between the comparative second quarters is reflective of higher salary costs which we consider necessary in order to remain competitive in our industry. 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 June 30, 2011, compared to June 30, 2010, decreased slightly, by 2%, primarily due to the departure of Encore transition employees who did not accept permanent positions with Denbury and who completed their transition period. However, prior to the Encore Merger, our headcount was 856 employees.

     Additional expense attributable to the legacy Encore office leases and the new Denbury headquarters lease, together with related moving costs, contributed to the higher cash G&A expense during the first six months of 2011. Additionally, stock-based compensation expense increased $2.3 million for the second quarter 2011 when compared to levels in the same period of 2010, due primarily to higher compensation levels.

     Gross cash G&A expenses decreased $7.6 million, or 11% from levels in the first quarter of 2011, due primarily to lower compensation and employee-related costs and lower professional fees in the current quarter. The first quarter of 2011 included higher payroll tax burdens and   401(k) matching contribution associated with bonus payouts, the true-up of long-term incentive compensation estimates, incremental costs associated with relocating our headquarters and higher professional fees associated with year-end work.

     The increase in gross G&A expense during the three and six months ended June 30, 2011, as compared to those costs in the same periods of 2010, 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 from acquisitions, additional tertiary operations, drilling activity during the past year, and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 8% and 20% during the three and six months ended June 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.

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DENBURY RESOURCES INC.

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

     The net effect of these changes resulted in a 1% decrease (a 29% increase on a per BOE basis) in G&A expense between the comparable second quarters of 2011 and 2010. Lower production in the most recent quarter attributable to the 2010 sale of properties was the primary factor relating to the higher cost per BOE, 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.

Interest and Financing Expenses

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per BOE data and interest rates	2011			2010			2011			2010
Cash interest	$	50,509		$	60,966		$	104,715		$	105,940
Non-cash interest		4,934			6,367			10,462			9,121
Less: capitalized interest		(13,194	)		(23,850	)		(24,151	)		(45,162	)
Interest expense, net	$	42,249		$	43,483		$	91,026		$	69,899
Interest income and other	$	4,955		$	4,520		$	8,004		$	6,390
Net cash interest expense and other income per BOE (1)	$	5.54		$	4.43		$	6.31		$	4.53
Average debt outstanding	$	2,305,104		$	3,152,564		$	2,409,284		$	2,689,894
Average interest rate (2)		8.8	%		7.7	%		8.7	%		7.9	%

(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 $10.5 million during the three month period ending June 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 interest. Year-to-date cash interest expense remained relatively consistent with that incurred in the same period in 2010. The decrease in cash interest expense during both the three and six month comparative periods was offset by lower capitalized interest relating primarily to the Green Pipeline, which was completed and placed into service at the end of June 2010.

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DENBURY RESOURCES INC.

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

Depletion, Depreciation, and Amortization

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per BOE data	2011		2010		2011		2010
Depletion, depreciation, and amortization (“DD&A”) of oil and natural gas properties	$	91,961	$	116,034	$	174,047	$	187,231
Depletion and depreciation of CO2 assets		4,588		5,680		9,178		10,980
Asset retirement obligations		1,696		1,692		3,259		2,799
Depreciation of other fixed assets		5,250		5,803		10,605		10,071
Total DD&A	$	103,495	$	129,209	$	197,089	$	211,081
DD&A per BOE:
Oil and natural gas properties	$	15.85	$	15.38	$	15.24	$	15.28
CO2 assets and other fixed assets		1.67		1.50		1.70		1.69
Total DD&A cost per BOE	$	17.52	$	16.88	$	16.94	$	16.97

     Depletion of oil and natural gas properties decreased on an absolute dollars basis during the three and six months ended June 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. Depletion of oil and gas properties increased on a per BOE basis during the second quarter of 2011 compared to 2010, primarily due to higher finding and development costs per barrel associated with the incremental Bakken capital program and upward revisions in estimated future development costs.

     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 six months ended June 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 months ended June 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 June 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.

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 $2.0 million and $4.4 million for the three and six months ended June 30, 2011, respectively, associated with the Encore Merger, including $1.8 million and $3.6 million, respectively, related to severance costs. Transaction and other costs of $22.8 million and $67.8 million for the three and six months ended June 30, 2010, respectively, included $19.5 million and $20.7 million, respectively, of severance costs, and were significantly higher than 2011 levels. We anticipate that these severance costs will decline in the remainder of 2011 as the integration winds down and fewer former Encore transition employees remain.

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DENBURY RESOURCES INC.

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

Income Taxes

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per BOE amounts and tax rates	2011			2010			2011			2010
Current income tax provision	$	12,028		$	6,941		$	11,180		$	7,610
Deferred income tax provision		152,528			74,422			144,620			150,694
Total income tax provision	$	164,556		$	81,363		$	155,800		$	158,304
Average income tax provision per BOE	$	27.85		$	10.63		$	13.39		$	12.73
Effective tax rate		38.8	%		35.1	%		38.9	%		38.7	%

     Our income taxes are based on an estimated statutory rate of approximately 38%. Our effective tax rate for the second quarter of 2011 was slightly higher compared to our statutory rate, primarily due to nondeductible expenses. Our effective tax rate for the second quarter of 2010 was lower due to the remeasurement of our deferred tax liabilities as a result of the May 2010 sale of certain legacy Encore properties in the Permian Basin, Mid-continent area and East Texas Basin (the “Southern Assets”), which resulted in an income tax benefit of approximately $3 million recorded in the second quarter of 2010. The nondeductible expenses in 2011 and the income tax benefit recorded in 2010 resulted in a slight increase in the effective tax rate, to 38.9%, during the six months ended June 30, 2011, as compared to 38.7% in the six months ended June 30, 2010. The current income tax expense represents our state income taxes during the three and six months ended June 30, 2011 and 2010.

     As of June 30, 2011, we had an estimated $39.8 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.5 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 2024. 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 injectant costs, and the elimination of the percentage depletion allowance. 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. 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						Six Months Ended
	June 30,						June 30,
Per BOE data	2011			2010			2011			2010
Oil and natural gas revenues	$	100.06		$	63.76		$	94.33		$	65.85
Gain (loss) on settlements of derivative contracts		(1.85	)		0.37			(0.80	)		(4.58	)
Lease operating expenses		(21.99	)		(16.69	)		(22.10	)		(18.01	)
Production taxes and marketing expenses		(6.72	)		(4.98	)		(6.23	)		(4.62	)
Production netback		69.50			42.46			65.20			38.64
Non-tertiary CO2 operating margin		0.59			0.39			0.53			0.49
General and administrative expenses		(5.23	)		(4.07	)		(6.43	)		(5.14	)
Transactions and other costs related to the Encore Merger		(0.34	)		(2.98	)		(0.38	)		(5.45	)
Net cash interest expense and other income		(5.54	)		(4.43	)		(6.31	)		(4.53	)
Current income taxes and other		(0.74	)		0.10			0.28			0.66
Changes in assets and liabilities relating to operations		9.22			3.95			(7.90	)		6.23
Cash flow from operations		67.46			35.42			44.99			30.90
DD&A		(17.52	)		(16.88	)		(16.94	)		(16.97	)
Deferred income taxes		(25.82	)		(9.72	)		(12.43	)		(12.12	)
Gain on sale of interests in Genesis		—			—			—			8.17
Loss on early extinguishment of debt		(0.06	)		—			(1.39	)		—
Non-cash fair value derivative adjustments		31.12			16.45			0.99			18.25
Net income attributable to noncontrolling interest		—			1.95			—			1.47
Changes in assets and liabilities and other non-cash items		(11.30	)		(9.53	)		5.85			(11.02	)
Net income attributable to Denbury stockholders	$	43.88		$	17.69		$	21.07		$	18.68

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 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; changes in interest rates; general economic conditions; competition and government regulations; 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. These debt agreements expose us to market risk related to changes in interest rates. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies. The fair value of the subordinated debt is based on quoted market prices. The following table presents the carrying and fair values of our debt, along with average interest rates at June 30, 2011:

													Carrying		Fair
In thousands, except percentages	2014		2015		2016		2017		2020		2021		Value		Value
Variable rate debt:
Bank Credit Agreement	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Fixed rate debt:
9.5% Senior Subordinated Notes due 2016		—		—		224,920		—		—		—		238,142		249,942
9.75% Senior Subordinated Notes due 2016		—		—		426,350		—		—		—		406,354		476,446
8.25% Senior Subordinated Notes due 2020		—		—		—		—		996,273		—		996,273		1,085,938
6.375% Senior Subordinated Notes due 2021		—		—		—		—		—		400,000		400,000		400,000
Other Subordinated Notes		1,072		485		—		2,250		—		—		3,843		3,807

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 June 30, 2011, our commodity derivative contracts were recorded at their fair value, which was a net liability of approximately $32.5 million (excluding $15.6 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 less than 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 June 30, 2011.

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DENBURY RESOURCES INC.

     Based on NYMEX crude oil and natural gas futures prices as of June 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	(Payment)			Receipt
Based on:
NYMEX futures prices as of June 30, 2011	$	(9,390	)	$	24,508
10% increase in prices		(81,222	)		18,312
10% decrease in prices		(2,952	)		30,703

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 $8.8 million unrealized gain or loss, respectively, as of June 30, 2011.

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 June 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 second 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.

37

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 second quarter of 2011, consisting entirely of 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
April 2011		17,272	$	23.97		—	$	—
May 2011		9,466		21.28		—		—
June 2011		14,479		19.95		—		—
Total		41,217		21.94		—	$	—

Item 6. Exhibits

Exhibit	Description
3.1	Amended and Restated Bylaws of Denbury Resources Inc. effective as of June 17, 2011 (incorporated by reference as Exhibit 3.1 of our Form 8-K filed on June 21, 2011).
4.1	Fifth Amendment to Credit Agreement dated as of March 9, 2010, dated as of May 19, 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 99.1 of our Form 8-K filed on May 20, 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.

38

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: August 8, 2011

39

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.

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

40

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.

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

41

EX-32

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 June 30, 2011 (the “Report”) of Denbury Resources Inc. (“Denbury”) as filed with the Securities and Exchange Commission on August 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: August 8, 2011	/s/ Phil Rykhoek
	Phil Rykhoek
	Chief Executive Officer
Dated: August 8, 2011	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

42

XML



Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Current assets
Allowance for trade and other receivables	$ 486,000	$ 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	402,508,885	400,291,033
Treasury stock, shares	193,177	78,524

XML



Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Revenues and other income
Oil, natural gas, and related product sales	$ 591,099,000	$ 488,028,000	$ 1,097,291,000	$ 818,914,000
CO2 sales and transportation fees	5,343,000	4,690,000	10,267,000	9,187,000
Gain on sale of interests in Genesis	0	(28,000)	0	101,540,000
Interest income and other income	4,955,000	4,520,000	8,004,000	6,390,000
Total revenues and other income	601,397,000	497,210,000	1,115,562,000	936,031,000
Expenses
Lease operating expenses	129,932,000	127,743,000	257,029,000	223,963,000
Production taxes and marketing expenses	39,688,000	38,100,000	72,439,000	57,417,000
CO2 discovery and operating expenses	1,869,000	1,681,000	4,023,000	3,049,000
General and administrative	30,900,000	31,192,000	74,746,000	63,901,000
Interest, net of amounts capitalized	42,249,000	43,483,000	91,026,000	69,899,000
Depletion, depreciation, and amortization	103,495,000	129,209,000	197,089,000	211,081,000
Derivatives expense (income)	(172,904,000)	(128,674,000)	(2,154,000)	(169,899,000)
Loss on early extinguishment of debt	348,000	0	16,131,000	0
Transaction and other costs	2,018,000	22,784,000	4,377,000	67,783,000
Total expenses	177,595,000	265,518,000	714,706,000	527,194,000
Income (loss) before income taxes	423,802,000	231,692,000	400,856,000	408,837,000
Income tax provision (benefit)
Current income taxes	12,028,000	6,941,000	11,180,000	7,610,000
Deferred income taxes	152,528,000	74,422,000	144,620,000	150,694,000
Consolidated net income (loss)	259,246,000	150,329,000	245,056,000	250,533,000
Less: net income attributable to noncontrolling interest	0	(14,962,000)	0	(18,278,000)
Net income (loss) attributable to Denbury stockholders	$ 259,246,000	$ 135,367,000	$ 245,056,000	$ 232,255,000
Net income (loss) per common share
Basic	$ 0.65	$ 0.34	$ 0.62	$ 0.67
Diluted	$ 0.64	$ 0.34	$ 0.61	$ 0.66
Weighted average common shares outstanding
Basic	398,631,000	395,548,000	398,032,000	345,126,000
Diluted	403,919,000	400,867,000	403,703,000	350,326,000

XML



Supplemental Information (Tables)

6 Months Ended

Jun. 30, 2011

Supplemental Information (Tables) [Abstract]

Accounts Payable and Accrued Liabilities

		June 30,		December 31,
In thousands		2011		2010
Accounts payable		$	72,830	$	47,660
Accrued exploration and development costs			96,910		101,758
Accrued compensation			26,760		39,757
Accrued lease operating expense			25,100		23,557
Accrued interest			61,166		57,077
Taxes payable			16,537		34,371
Other			34,650		41,818
	Total	$	333,953	$	345,998

Supplemental Cash Flow Information

	Six Months Ended
	June 30,
In thousands	2011		2010
Cash paid for interest, expensed	$	72,774	$	43,296
Cash paid for interest, capitalized		24,151		45,162
Cash paid for income taxes		31,072		11,920
Cash received for income tax refunds		20,841		13,093
Increase in liabilities for capital expenditures		25,141		46,170
Issuance of Denbury common stock in connection with the Encore Merger		-		2,085,681

XML



Document and Entity Information	6 Months Ended
	Jun. 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	Jun. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
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	402,350,295

XML



Basis of Presentation (Details Textuals) (USD $) Share data in Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 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	14,962,000	0	18,278,000
Weighted average common shares - basic restricted stock	3.40	3.50	3.60	3.30
Net unrealized gains on available-for-sale securities, net of tax	7,139,000	0	2,976,000	0
Unrealized gain (loss) on short term investment, tax	4,375,000	0	1,824,000	0
Distribution on Vanguard common units	$ 1,700,000		$ 3,500,000

XML



Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 4. Derivative Instruments and Hedging Activities

Oil and Natural Gas Derivative Contracts

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				Six Months Ended
			June 30,				June 30,
In thousands			2011		2010		2011		2010
Oil
	Payment on settlements of derivative contracts		$	16,972	$	13,829	$	22,000	$	77,379
	Fair value adjustments to derivative contracts - expense (income)			(187,194)		(145,099)		(20,130)		(206,920)
		Total derivative expense (income) - oil		(170,222)		(131,270)		1,870		(129,541)
Natural Gas
	Receipt on settlements of derivative contracts			(6,030)		(16,630)		(12,646)		(20,379)
	Fair value adjustments to derivative contracts - expense (income)			3,348		19,909		8,622		(19,109)
		Total derivative expense (income) - natural gas		(2,682)		3,279		(4,024)		(39,488)
Ineffectiveness on interest rate swaps				-		(683)		-		(870)
		Derivative income	$	(172,904)	$	(128,674)	$	(2,154)	$	(169,899)

Commodity Derivative Contracts Not Classified as Hedging Instruments

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

				NYMEX Contract Prices Per Bbl
		Type of		Weighted Average Price
Year	Months	Contract	Bbls/d	Swap		Floor		Ceiling
Oil Contracts
2011	July - Sept	Swap	625		79.18		-		-
		Collar	42,500		-		70.35		100.09
		Put	6,625		-		69.53		-
	Total July - Sept 2011		49,750
	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

			Type of		Weighted Average Swap
Year		Months	Contract	MMBtu/d	Price per MMBtu
Natural Gas Contracts
	2011	July - Sept	Swap	33,500	$	6.27
		Total July-Sept 2011		33,500
		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

As of June 30, 2011 and December 31, 2010, we had $15.6million and $26.7million, respectively, of deferred premiums payable, which relate to various oil and natural gas floor contracts and are payable on a monthly basis through January 2013. These premiums are excluded from the above tables.

Additional Disclosures about Derivative Instruments

At June 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)
					June 30,		December 31,
Type of Contract				Balance Sheet Location	2011		2010
					(In thousands)
Derivatives not designated as hedging instruments
	Derivative asset
		Oil contracts		Derivative assets - current	$	1,462	$	3,050
		Natural gas contracts		Derivative assets - current		17,860		21,192
		Oil contracts		Derivative assets - long-term		11,281		1,301
		Natural gas contracts		Derivative assets - long-term		6,328		11,618
	Derivative liability
		Oil contracts		Derivative liabilities - current		(67,196)		(55,256)
		Deferred premiums		Derivative liabilities - current		(14,431)		(22,928)
		Oil contracts		Derivative liabilities - long-term		(2,228)		(25,906)
		Deferred premiums		Derivative liabilities - long-term		(1,150)		(3,781)
			Total derivatives not designated as hedging instruments		$	(48,074)	$	(70,710)

XML



Acquisitions and Divestitures (Details) (Riley Ridge [Member], USD $)	Oct. 15, 2010
Riley Ridge [Member]
Riley Ridge Purchase Price Allocation
Oil and natural gas properties	$ 19,646,000
CO2 and other non-hydrocarbon gases properties	10,907,000
Pipelines and plants	72,070,000
Prepaid construction and drilling costs	9,346,000
Other assets	19,300,000
Asset retirement obligations	(472,000)
Goodwill	1,460,000
Assets Acquired (Liabilities Assumed), Total	$ 132,257,000

XML



Fair Value Measurements (Details 2) (USD $)	Jun. 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	238,142,000	239,509,000
Senior Subordinated Notes, Estimated Fair Value	249,942,000	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	406,354,000	404,211,000
Senior Subordinated Notes, Estimated Fair Value	476,446,000	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	1,085,938,000	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	$ 400,000,000	$ 0

XML



Basis of Presentation (Details 1)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 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	2,412,000	4,223,000	2,297,000	4,785,000
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	24,000	35,000	15,000	413,000

XML



Significant Accounting Policies (Policies)

6 Months Ended

Jun. 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 June 30, 2011,ourconsolidated results of operations for the three andsix months ended June 30, 2011 and 2010, and our consolidated cash flows for the six months ended June 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 Sheets as of December 31, 2010 and June 30, 2011,nor do our Unaudited Condensed Consolidated Statements of Operationsfor the three and six months ended June 30, 2011 or our Unaudited Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2011 include ENP's results of operations or cash flows.As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010, “Net income attributable to noncontrolling interest” of $15.0 million and $18.3 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

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 six months ended June 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 3.6million shares for the three and six months ended ended June 30, 2011, respectively, and 3.5 million and 3.3 million sharesfor the three and six months endedJune 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		Six Months Ended
	June 30,		June 30,
In thousands	2011	2010	2011	2010
Stock options and SARs	2,412	4,223	2,297	4,785
Restricted stock	24	35	15	413

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 June 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 $1.7 million and $3.5 million on the Vanguard common units we own for the three and six months ended June 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 $7.1 million (net ofa taxbenefit of $4.4 million) and $3.0 million (net of a tax benefit of $1.8 million) for the three and six months endedJune 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		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Other comprehensive income (loss), net of income tax:
Tax effect of changes in value on available-for-sale securities	$ (4,375,000)	$ 0	$ (1,824,000)	$ 0
Tax for interest rate lock derivative contracts reclassified to income	10,000	10,000	21,000	21,000
Tax for change in fair value of interest rate lock derivative contracts designated as a hedge	$ 0	$ 8,000	$ 0	$ 18,000

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Derivative Instruments and Hedging Activities (Details Textual) (USD $) In Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Derivative Instruments and Hedging Activities (Textuals) [Abstract]
Deferred premiums payable	$ 15.60	$ 26.70

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Supplemental Information

6 Months Ended

Jun. 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:

		June 30,		December 31,
In thousands		2011		2010
Accounts payable		$	72,830	$	47,660
Accrued exploration and development costs			96,910		101,758
Accrued compensation			26,760		39,757
Accrued lease operating expense			25,100		23,557
Accrued interest			61,166		57,077
Taxes payable			16,537		34,371
Other			34,650		41,818
	Total	$	333,953	$	345,998

Supplemental Cash Flow Information

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

	Six Months Ended
	June 30,
In thousands	2011		2010
Cash paid for interest, expensed	$	72,774	$	43,296
Cash paid for interest, capitalized		24,151		45,162
Cash paid for income taxes		31,072		11,920
Cash received for income tax refunds		20,841		13,093
Increase in liabilities for capital expenditures		25,141		46,170
Issuance of Denbury common stock in connection with the Encore Merger		-		2,085,681

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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2011

Table Text Block Supplement [Abstract]

Riley Ridge Purchase Price Allocation

In thousands
Oil and natural gas properties		$	19,646
CO2 and other non-hydrocarbon gases properties			10,907
Pipelines and plants			72,070
Prepaid construction and drilling costs			9,346
Other assets			19,300
Asset retirement obligations			(472)
Goodwill			1,460
	Total	$	132,257

Proforma revenue and net income (loss)

		Pro Forma Results
In thousands, except per share amounts		Three Months Ended June 30, 2010		Six Months Ended June 30, 2010
Pro forma total revenues		$	497,210	$	1,112,481
Pro forma net income attributable to Denbury stockholders			135,494		247,423
Pro forma net income per common share:
	Basic	$	0.34	$	0.63
	Diluted		0.34		0.62

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Commitments and Contingencies

6 Months Ended

Jun. 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 in Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("IGCC") 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 200 MMCF/d of CO2 from the MBFP project in2015, 115 MMcf/d of CO2 from the IGCC 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.TheIGCC and Air Products plants are currently being constructed and MBFP is in the initial stages ofconstruction but its completion is still contingent upon securing debt financing and equity commitments and receipt of all necessary consents and approvals.

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.  We have received a $15.0 million assessment from the Mississippi taxing authority for use tax, penalties and interest covering the 2004-2007 period.  We believe this assessment is significantly in excess of any amounts owed and we are appealing the assessment. We do not believe the outcome of this matter will have a material adverse effect on our financial position or results of operations.

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		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Ineffectiveness on interest rate swaps	$ 0	$ (683,000)	$ 0	$ (870,000)
Derivatives expense (income)	(172,904,000)	(128,674,000)	(2,154,000)	(169,899,000)
Oil contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Payment (receipt) on settlements of derivative contracts	16,972,000	13,829,000	22,000,000	77,379,000
Fair value adjustments to derivative contracts - expense (income)	(187,194,000)	(145,099,000)	(20,130,000)	(206,920,000)
Total derivatives expense (income) - oil & natural gas	(170,222,000)	(131,270,000)	1,870,000	(129,541,000)
Natural Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Payment (receipt) on settlements of derivative contracts	(6,030,000)	(16,630,000)	(12,646,000)	(20,379,000)
Fair value adjustments to derivative contracts - expense (income)	3,348,000	19,909,000	8,622,000	(19,109,000)
Total derivatives expense (income) - oil & natural gas	$ (2,682,000)	$ 3,279,000	$ (4,024,000)	$ (39,488,000)

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

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

Fair Value Measurements

Note 5. Fair Value Measurements

Fair Value Hierarchy

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 Hierarchy

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
June 30, 2011
Assets
	Short-term investments		$	88,220	$	-	$	-	$	88,220
	Oil and natural gas derivative contracts			-		30,293		6,638		36,931
Liabilities
	Oil and natural gas derivative contracts			-		(69,424)		-		(69,424)
		Total	$	88,220	$	(39,131)	$	6,638	$	55,727
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 six months endedJune 30, 2011 and 2010

		Three Months Ended				Six Months Ended
		June 30,				June 30,
In thousands		2011		2010		2011		2010
Balance, beginning of period		$	15,346	$	50,518	$	16,478	$	-
	Unrealized gains/(losses) on commodity derivative contracts included in earnings		(7,386)		126		(7,076)		14,899
	Commodity derivative contracts acquired from Encore		-		-		-		38,093
	Receipts on settlement of commodity derivative contracts		(1,322)		(10,361)		(2,764)		(12,709)
Balance, end of period			6,638		40,283	$	6,638	$	40,283

Since we donot use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives 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:

		June 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		238,142		249,942		239,509		249,661
	9¾% Senior Subordinated Notes due 2016		406,354		476,446		404,211		475,380
	8¼% Senior Subordinated Notes due 2020		996,273		1,085,938		996,273		1,080,956
	6⅜% Senior Subordinated Notes due 2021		400,000		400,000		-		-

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 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 $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash flows from operating activities
Consolidated net income (loss)	$ 245,056,000	$ 250,533,000
Adjustments needed to reconcile to net cash provided by operating activities
Depletion, depreciation, and amortization	197,089,000	211,081,000
Deferred income taxes	144,620,000	150,694,000
Gain on sale of interests in Genesis	0	(101,540,000)
Stock-based compensation	18,132,000	17,130,000
Non-cash fair value derivative adjustments	(11,508,000)	(226,899,000)
Loss on early extinguishment of debt	16,131,000	0
Other, net	5,755,000	5,871,000
Changes in operating assets and liabilities:
Accrued production receivable	(35,068,000)	52,075,000
Trade and other receivables	(28,258,000)	10,058,000
Other assets	(2,920,000)	(3,134,000)
Accounts payable and accrued liabilities	(48,471,000)	12,066,000
Oil and natural gas production payable	30,135,000	11,236,000
Increase (Decrease) in Other Operating Liabilities	(7,340,000)	(4,880,000)
Net cash provided by operating activities	523,353,000	384,291,000
Cash flows used for investing activities
Oil and natural gas capital expenditures	(471,601,000)	(317,173,000)
Acquisitions of oil and natural gas properties	(32,482,000)	(24,243,000)
Cash paid in Encore Merger, net of cash acquired	0	(801,489,000)
CO2 and other non-hydrocarbon gases capital expenditures	(31,731,000)	(44,274,000)
Pipelines and plants capital expenditures	(98,669,000)	(108,177,000)
Net proceeds from sales of oil and natural gas properties and equipment	0	881,344,000
Net proceeds from sale of interests in Genesis	0	162,622,000
Payments for (proceeds from) other investing activities	1,643,000	(7,224,000)
Net cash used for investing activities	(632,840,000)	(258,614,000)
Cash flows from financing activities
Bank repayments	(130,000,000)	(1,514,000,000)
Bank borrowings	130,000,000	1,149,000,000
Repayment of senior subordinated notes	(525,000,000)	(609,424,000)
Premium paid on repayment of senior subordinated notes	(13,137,000)	(7,214,000)
Net proceeds from issuance of senior subordinated notes	400,000,000	1,000,000,000
Net proceeds from issuance of common stock	9,203,000	5,540,000
Costs of debt financing	(13,274,000)	(76,232,000)
ENP distributions to noncontrolling interest	0	(12,209,000)
Other	(8,382,000)	(14,255,000)
Net cash provided by (used for) financing activities	(150,590,000)	(78,794,000)
Net increase (decrease) in cash and cash equivalents	(260,077,000)	46,883,000
Cash and cash equivalents at beginning of period	381,869,000	20,591,000
Cash and cash equivalents at end of period	$ 121,792,000	$ 67,474,000

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Basis of Presentation

6 Months Ended

Jun. 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 June 30, 2011,ourconsolidated results of operations for the three andsix months ended June 30, 2011 and 2010, and our consolidated cash flows for the six months ended June 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 Sheets as of December 31, 2010 and June 30, 2011,nor do our Unaudited Condensed Consolidated Statements of Operationsfor the three and six months ended June 30, 2011 or our Unaudited Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2011 include ENP's results of operations or cash flows.As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010, “Net income attributable to noncontrolling interest” of $15.0 million and $18.3 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 six months ended June 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		Six Months Ended
		June 30,		June 30,
In thousands		2011	2010	2011	2010
Basic weighted average common shares		398,631	395,548	398,032	345,126
Potentially dilutive securities:
	Stock options and SARs	3,946	3,980	4,251	3,835
	Performance equity awards	23	146	12	312
	Restricted stock	1,319	1,193	1,408	1,053
Diluted weighted average common shares		403,919	400,867	403,703	350,326

Basic weighted average common shares excludes 3.4million and 3.6million shares for the three and six months ended ended June 30, 2011, respectively, and 3.5 million and 3.3 million sharesfor the three and six months endedJune 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		Six Months Ended
	June 30,		June 30,
In thousands	2011	2010	2011	2010
Stock options and SARs	2,412	4,223	2,297	4,785
Restricted stock	24	35	15	413

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 June 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 $1.7 million and $3.5 million on the Vanguard common units we own for the three and six months ended June 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 $7.1 million (net ofa taxbenefit of $4.4 million) and $3.0 million (net of a tax benefit of $1.8 million) for the three and six months endedJune 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 June 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 $1.7 million and $3.5 million on the Vanguard common units we own for the three and six months ended June 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 $7.1 million (net ofa taxbenefit of $4.4 million) and $3.0 million (net of a tax benefit of $1.8 million) for the three and six months endedJune 30,2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 FASCFair Value Measurementstopic 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 ourconsolidated financial statements, but may require additional disclosures.

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 ourfiscal 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.

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Commitments and Contingencies (Details) (USD $)	6 Months Ended
	Jun. 30, 2011
Long-term Purchase Commitment [Line Items]
Expected amount of CO2 to be delivered by third parties in future years	365 MMcf/d
Commitments and Contingencies (Textuals) [Abstract]
Assessment from Mississippi taxing authority for use tax, penalties and interest	$ 15,000,000
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	200 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 IGCC 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

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Long Term Debt (Details Textuals) (USD $)	3 Months Ended		6 Months Ended							1 Months Ended					1 Months Ended						6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	May 31, 2011	Mar. 31, 2010	Jun. 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]	Jun. 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]	Jun. 30, 2011 9.5% Senior Subordinated Notes due 2016 [Member]	Dec. 31, 2010 9.5% Senior Subordinated Notes due 2016 [Member]	Jun. 30, 2011 9.75% Senior Subordinated Notes due 2016 [Member]	Dec. 31, 2010 9.75% Senior Subordinated Notes due 2016 [Member]	Jun. 30, 2011 6 3/8% Senior Subordinated Notes Due 2021 [Member]	Feb. 28, 2011 6 3/8% Senior Subordinated Notes Due 2021 [Member]	Jun. 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										19,996,000	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	1,600,000,000
Debt Instrument, Unamortized Premium												0		427,000			13,222,000	14,589,000					37,000	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	$ 348,000	$ 0	$ 16,131,000	$ 0

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2011

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 2. Acquisitions and Divestitures

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 June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $200.6 million and $260.9 million, respectively, of oil, natural gas sales and related product sales related to the Encore Merger. For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $137.8 million and $180.7 million, respectively,of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) related to the Encore Merger. We recognized a total of $2.0 million and $22.8 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 June 30, 2011 and 2010, respectively, and $4.4 million and $67.8 million of such costs for the six months ended June 30, 2011 and 2010, respectively.

2010Acquisition 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 a working interest in a gas plant, which is 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.

This acquisition meets the definition of a business under the FASC Business Combinations topic. The following table presents a summary of the preliminaryfair value of these Riley Ridge assets acquired and liabilities assumed:

In thousands
Oil and natural gas properties		$	19,646
CO2 and other non-hydrocarbon gases properties			10,907
Pipelines and plants			72,070
Prepaid construction and drilling costs			9,346
Other assets			19,300
Asset retirement obligations			(472)
Goodwill			1,460
	Total	$	132,257

On August 1, 2011, we acquired the remaining working interest in Riley Ridge and an additional interest in the adjoining acreage and became the operator of both projects; see Note 8, Subsequent Event, for more information.

Pro Forma Information

Had the Encore Merger and October 2010 Riley Ridge acquisition bothoccurred on January 1, 2010, our combined pro forma revenues and net income for the three and six months ended June 30, 2010, would have been as follows:

		Pro Forma Results
In thousands, except per share amounts		Three Months Ended June 30, 2010		Six Months Ended June 30, 2010
Pro forma total revenues		$	497,210	$	1,112,481
Pro forma net income attributable to Denbury stockholders			135,494		247,423
Pro forma net income per common share:
	Basic	$	0.34	$	0.63
	Diluted		0.34		0.62

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 Sale of Southern Assets

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. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

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Acquisitions and Divestitures (Details 1) (USD $)	3 Months Ended	6 Months Ended
	Jun. 30, 2010	Jun. 30, 2010
Proforma revenue and net income (loss)
Pro forma total revenues	$ 497,210,000	$ 1,112,481,000
Pro forma net income attributable to Denbury stockholders	$ 135,494,000	$ 247,423,000
Pro forma net income per common share:
Basic	$ 0.34	$ 0.63
Diluted	$ 0.34	$ 0.62

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Derivative Instruments and Hedging Activities (Details 1)	Jun. 30, 2011
Year 2011 [Member] | Collars [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	70.35
Ceiling price	100.09
Volume per Day	42,500
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] | Q3 [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] | 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] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	6.27
Volume per Day	33,500
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] | Q3 [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] | 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] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	49,750
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

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Subsequent Events (Details Textuals) (Riley Ridge Phase 2 [Member], USD $) In Millions, unless otherwise specified	Aug. 01, 2011
Riley Ridge Phase 2 [Member]
Subsequent Event [Line Items]
Working interest in business acquisition	57.50%
Contract price before closing adjustments, including contingent consideration, for acquisition	$ 191.00
Contingent payment to be paid at the time the property's gas processing facility is operational and meets specific performance conditions	$ 15.00
Business Acquisition Percentage Of Additional Working Interests	33.00%

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Long-Term Debt (Details) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Credit Agreement	$ 0	$ 0
Capital Lease Obligations	5,620,000	6,806,000
Total	2,296,734,000	2,424,156,000
Less current obligations	8,622,000	7,948,000
Long-term debt and capital lease obligations	2,288,112,000	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	238,142,000	239,509,000
9.75% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	406,354,000	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	3,842,000	3,848,000
NEJD Financing [Member]
Debt Instrument [Line Items]
Financing Lease Obligations	165,550,000	167,331,000
Free State Financing [Member]
Debt Instrument [Line Items]
Financing Lease Obligations	$ 80,953,000	$ 81,188,000

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Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2011

Basis of Presentation (Tables) [Abstract]

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

		Three Months Ended		Six Months Ended
		June 30,		June 30,
In thousands		2011	2010	2011	2010
Basic weighted average common shares		398,631	395,548	398,032	345,126
Potentially dilutive securities:
	Stock options and SARs	3,946	3,980	4,251	3,835
	Performance equity awards	23	146	12	312
	Restricted stock	1,319	1,193	1,408	1,053
Diluted weighted average common shares		403,919	400,867	403,703	350,326

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
In thousands	2011	2010	2011	2010
Stock options and SARs	2,412	4,223	2,297	4,785
Restricted stock	24	35	15	413

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Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-Term Debt [Abstract]

Long-Term Debt

Note 3. Long-Term Debt

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

		June 30,		December 31,
In thousands		2011			2010
Bank Credit Agreement		$	-		$	-
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 $13,222 and $14,589, respectively			238,142			239,509
9¾% Senior Subordinated Notes due 2016, including discount of $19,996 and $22,139, respectively			406,354			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 $37 and $41, respectively			3,842			3,848
NEJD financing			165,550			167,331
Free State financing			80,953			81,188
Capital lease obligations			5,620			6,806
	Total		2,296,734			2,424,156
	Less current obligations		(8,622)			(7,948)
	Long-term debt and capital lease obligations	$	2,288,112		$	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. All of our100% owned subsidiaries, other than minor subsidiaries, 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 “Amendment”). The Amendment reconfirms our current borrowing base of $1.6 billion, 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 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 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.

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 $0.3 million and $16.1 million loss during the three and six months ended June 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)

6 Months Ended

Jun. 30, 2011

Table Text Block Supplement [Abstract]

Components of Long-Term Debt

		June 30,		December 31,
In thousands		2011			2010
Bank Credit Agreement		$	-		$	-
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 $13,222 and $14,589, respectively			238,142			239,509
9¾% Senior Subordinated Notes due 2016, including discount of $19,996 and $22,139, respectively			406,354			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 $37 and $41, respectively			3,842			3,848
NEJD financing			165,550			167,331
Free State financing			80,953			81,188
Capital lease obligations			5,620			6,806
	Total		2,296,734			2,424,156
	Less current obligations		(8,622)			(7,948)
	Long-term debt and capital lease obligations	$	2,288,112		$	2,416,208

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Supplemental Information (Details) (USD $)	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Accounts Payable and Accrued Liabilities
Accounts payable	$ 72,830,000	$ 47,660,000
Accrued exploration and development costs	96,910,000	101,758,000
Accrued compensation	26,760,000	39,757,000
Accrued lease operating expense	25,100,000	23,557,000
Accrued interest	61,166,000	57,077,000
Taxes payable	16,537,000	34,371,000
Other Accrued Liabilities Current	34,650,000	41,818,000
Total	333,953,000	345,998,000
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	72,774,000	43,296,000
Cash paid for interest, capitalized	24,151,000	45,162,000
Cash paid for income taxes	31,072,000	11,920,000
Cash received for income tax refunds	20,841,000	13,093,000
Increase (decrease) in liabilities for capital expenditures	25,141,000	46,170,000
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			1 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Oct. 15, 2010 Riley Ridge [Member] Acres	May 31, 2010 Southern Assets [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
Revenues recognized from current period acquisitions		200,600,000		260,900,000
Transaction and other costs	2,018,000	22,784,000			4,377,000	67,783,000
Working interest in business acquisition							42.50%
Acreage for CO2 rights at Riley Ridge							28,000
Business Acquisition, Percentage of CO2 rights in additional 28,000 acres							33.00%
Net Field Operating Income		137,800,000		180,700,000
Net proceeds from sale of interest in Genesis									79,000,000	84,000,000
Pre tax gain on sale of interest in Genesis	0	(28,000)			0	101,540,000
Gain on sale of interest in Genesis after tax			63,000,000
Proceeds from Sale of Oil and Gas Property and Equipment					$ 0	$ 881,344,000		$ 892,100,000

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Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Expenses
Interest capitalized	$ 13,194,000	$ 23,850,000	$ 24,151,000	$ 45,162,000

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 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
June 30, 2011
Assets
	Short-term investments		$	88,220	$	-	$	-	$	88,220
	Oil and natural gas derivative contracts			-		30,293		6,638		36,931
Liabilities
	Oil and natural gas derivative contracts			-		(69,424)		-		(69,424)
		Total	$	88,220	$	(39,131)	$	6,638	$	55,727
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				Six Months Ended
		June 30,				June 30,
In thousands		2011		2010		2011		2010
Balance, beginning of period		$	15,346	$	50,518	$	16,478	$	-
	Unrealized gains/(losses) on commodity derivative contracts included in earnings		(7,386)		126		(7,076)		14,899
	Commodity derivative contracts acquired from Encore		-		-		-		38,093
	Receipts on settlement of commodity derivative contracts		(1,322)		(10,361)		(2,764)		(12,709)
Balance, end of period			6,638		40,283	$	6,638	$	40,283

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

		June 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		238,142		249,942		239,509		249,661
	9¾% Senior Subordinated Notes due 2016		406,354		476,446		404,211		475,380
	8¼% Senior Subordinated Notes due 2020		996,273		1,085,938		996,273		1,080,956
	6⅜% Senior Subordinated Notes due 2021		400,000		400,000		-		-

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Basis of Presentation (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Weighted average shares used in the basic and diluted net income per common share
Weighted average common shares - basic	398,631,000	395,548,000	398,032,000	345,126,000
Potentially dilutive securities:
Performance-Based Awards	23,000	146,000	12,000	312,000
Weighted average common shares - diluted	403,919,000	400,867,000	403,703,000	350,326,000
Stock Options and SARs [Member]
Potentially dilutive securities:
Stock options, SARs, and Restricted stock	3,946,000	3,980,000	4,251,000	3,835,000
Restricted Stock [Member]
Potentially dilutive securities:
Stock options, SARs, and Restricted stock	1,319,000	1,193,000	1,408,000	1,053,000

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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Condensed Consolidated Statements of Comprehensive Operations [Abstract]
Consolidated net income (loss)	$ 259,246,000	$ 150,329,000	$ 245,056,000	$ 250,533,000
Other comprehensive income (loss), net of income tax:
Net unrealized gains on available-for-sale securities, net of tax	(7,139,000)	0	(2,976,000)	0
Interest rate lock derivative contracts reclassified to income, net of tax	18,000	17,000	35,000	34,000
Change in deferred hedge loss on interest rate swaps, net of tax	0	(60,000)	0	(87,000)
Consolidated comprehensive income (loss)	252,125,000	150,286,000	242,115,000	250,480,000
Less: comprehensive income attributable to noncontrolling interest	0	(14,950,000)	0	(18,235,000)
Comprehensive income (loss) attributable to Denbury stockholders	$ 252,125,000	$ 135,336,000	$ 242,115,000	$ 232,245,000

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Subsequent Events

6 Months Ended

Jun. 30, 2011

Subsequent Events [Abstract]

Subsequent Events (Unaudited)

Note 8. Subsequent Event

On August 1, 2011,we acquired the remaining57.5% working interest in Riley Ridge 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 $191 million, including a $15 million contingent payment to be paid at the time the property's gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments including payment for capital expenditures incurred between the effective date of the purchase (April 1, 2011) and closing. We expect the gas processing facility to be operational during the fourth quarter of 2011.

The acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  We will account for our acquisition of Riley Ridge under the acquisition method of accounting, which will result in the allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition, with the excess purchase price, if any, being recognized as goodwill. We have not yet completed our initial calculation necessary to make this allocation.

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Derivative Instruments and Hedging Activities (Details 2) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Derivative financial instruments in Balance Sheet
Total derivatives not designated as hedging instruments	$ (48,074,000)	$ (70,710,000)
Oil contracts [Member] | Derivative assets-current [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	1,462,000	3,050,000
Natural Gas Contracts [Member] | Derivative assets-current [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	17,860,000	21,192,000
Oil contracts [Member] | Derivative assets - long - term [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	11,281,000	1,301,000
Natural Gas Contracts [Member] | Derivative assets - long - term [Member]
Derivative financial instruments in Balance Sheet
Derivative assets	6,328,000	11,618,000
Oil contracts [Member] | Derivative liabilities-current [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	67,196,000	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	14,431,000	22,928,000
Oil contracts [Member] | Derivative liabilities-long term [Member]
Derivative financial instruments in Balance Sheet
Derivative Liability	2,228,000	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	$ 1,150,000	$ 3,781,000

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities (Tables) [Abstract]

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

			Three Months Ended				Six Months Ended
			June 30,				June 30,
In thousands			2011		2010		2011		2010
Oil
	Payment on settlements of derivative contracts		$	16,972	$	13,829	$	22,000	$	77,379
	Fair value adjustments to derivative contracts - expense (income)			(187,194)		(145,099)		(20,130)		(206,920)
		Total derivative expense (income) - oil		(170,222)		(131,270)		1,870		(129,541)
Natural Gas
	Receipt on settlements of derivative contracts			(6,030)		(16,630)		(12,646)		(20,379)
	Fair value adjustments to derivative contracts - expense (income)			3,348		19,909		8,622		(19,109)
		Total derivative expense (income) - natural gas		(2,682)		3,279		(4,024)		(39,488)
Ineffectiveness on interest rate swaps				-		(683)		-		(870)
		Derivative income	$	(172,904)	$	(128,674)	$	(2,154)	$	(169,899)

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	July - Sept	Swap	625		79.18		-		-
		Collar	42,500		-		70.35		100.09
		Put	6,625		-		69.53		-
	Total July - Sept 2011		49,750
	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

			Type of		Weighted Average Swap
Year		Months	Contract	MMBtu/d	Price per MMBtu
Natural Gas Contracts
	2011	July - Sept	Swap	33,500	$	6.27
		Total July-Sept 2011		33,500
		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)
					June 30,		December 31,
Type of Contract				Balance Sheet Location	2011		2010
					(In thousands)
Derivatives not designated as hedging instruments
	Derivative asset
		Oil contracts		Derivative assets - current	$	1,462	$	3,050
		Natural gas contracts		Derivative assets - current		17,860		21,192
		Oil contracts		Derivative assets - long-term		11,281		1,301
		Natural gas contracts		Derivative assets - long-term		6,328		11,618
	Derivative liability
		Oil contracts		Derivative liabilities - current		(67,196)		(55,256)
		Deferred premiums		Derivative liabilities - current		(14,431)		(22,928)
		Oil contracts		Derivative liabilities - long-term		(2,228)		(25,906)
		Deferred premiums		Derivative liabilities - long-term		(1,150)		(3,781)
			Total derivatives not designated as hedging instruments		$	(48,074)	$	(70,710)

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 121,792,000	$ 381,869,000
Accrued production receivable	255,034,000	223,584,000
Trade and other receivables, net of allowance	153,018,000	114,149,000
Short-term investments	88,220,000	93,020,000
Derivative assets	19,322,000	24,242,000
Deferred tax assets	22,097,000	27,454,000
Total current assets	659,483,000	864,318,000
Oil and natural gas properties (using full cost accounting)
Proved	6,508,928,000	6,042,442,000
Unevaluated	952,452,000	870,130,000
CO2 and other non-hydrocarbon gases properties	572,957,000	523,423,000
Pipelines And Plant	1,445,214,000	1,378,239,000
Other property and equipment	138,671,000	120,641,000
Less accumulated depletion, depreciation, amortization, and impairment	2,403,741,000	2,197,517,000
Net property and equipment	7,214,481,000	6,737,358,000
Derivative assets	17,609,000	12,919,000
Goodwill	1,232,418,000	1,232,418,000
Other assets	215,432,000	218,050,000
Total assets	9,339,423,000	9,065,063,000
Current liabilities
Accounts payable and accrued liabilities	333,953,000	345,998,000
Oil and gas production payable	172,837,000	143,145,000
Derivative liabilities	81,627,000	78,184,000
Less current obligations	8,622,000	7,948,000
Other Liabilities, Current	4,070,000	4,070,000
Total current liabilities	601,109,000	579,345,000
Long-term liabilities
Long-term debt, net of current portion	2,288,112,000	2,416,208,000
Asset retirement obligations	86,109,000	81,290,000
Derivative liabilities	3,378,000	29,687,000
Deferred taxes	1,687,839,000	1,547,992,000
Other Liabilities, Noncurrent	24,562,000	29,834,000
Total long-term liabilities	4,090,000,000	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	3,074,335,000	3,045,937,000
Retained earnings	1,581,198,000	1,336,142,000
Accumulated other comprehensive income (loss)	(3,429,000)	(488,000)
Treasury stock, at cost	(4,193,000)	(1,284,000)
Total stockholders' equity	4,648,314,000	4,380,707,000
Total liabilities and stockholders' equity	$ 9,339,423,000	$ 9,065,063,000

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Fair Value Measurements (Details) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments	$ 88,220,000	$ 93,020,000
Oil and natural gas derivative contracts	36,931,000	37,161,000
Oil and natural gas derivative contracts	(69,424,000)	(81,162,000)
Total	55,727,000	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	88,220,000	93,020,000
Oil and natural gas derivative contracts	0	0
Oil and natural gas derivative contracts	0	0
Total	88,220,000	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	30,293,000	20,683,000
Oil and natural gas derivative contracts	(69,424,000)	(81,162,000)
Total	(39,131,000)	(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	6,638,000	16,478,000
Oil and natural gas derivative contracts	0	0
Total	$ 6,638,000	$ 16,478,000

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Fair Value Measurements (Details 1) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance, beginning of period	$ 15,346,000	$ 50,518,000	$ 16,478,000	$ 0
Unrealized gains on commodity derivative contracts included in net earnings	(7,386,000)	126,000	(7,076,000)	14,899,000
Commodity derivative contracts acquired from Encore	0	0	0	38,093,000
Receipts on settlement of commodity derivative contracts	(1,322,000)	(10,361,000)	(2,764,000)	(12,709,000)
Balance, end of period	$ 6,638,000	$ 40,283,000	$ 6,638,000	$ 40,283,000