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 March 31, 2012

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 jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5320 Legacy Drive, Plano, TX	75024
(Address of principal executive offices)	(Zip Code)

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

Not applicable

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

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

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

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

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

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

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

Class	Outstanding at April 30, 2012
Common Stock, $.001 par value	390,635,689

Denbury Resources Inc.

Table of Contents

		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011	3
	Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011	4
	Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three Months Ended March 31, 2012 and 2011	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	36
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Mine Safety Disclosures	37
Item 5.	Other Information	37
Item 6.	Exhibits	38
	Signatures	39
	Exhibit 4(a)
	Exhibit 10(a)
	Exhibit 10(b)
	Exhibit 10(c)
	Exhibit 31(a)
	Exhibit 31(b)
	Exhibit 32

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Resources Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

	March 31,			December 31,
	2012			2011
Assets
Current assets
Cash and cash equivalents	$	77,366		$	18,693
Restricted cash		140,131			—
Accrued production receivable		303,552			294,689
Trade and other receivables, net		150,379			164,446
Short-term investments		—			86,682
Derivative assets		23,015			47,402
Deferred tax assets		47,641			50,156
Other current assets		15,951			22,045
Total current assets		758,035			684,113
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		7,329,967			7,026,579
Unevaluated		995,352			1,157,106
CO2 properties		613,308			596,003
Pipelines and plants		1,755,679			1,701,756
Other property and equipment		162,363			157,674
Less accumulated depletion, depreciation, amortization, and impairment		(2,751,999	)		(2,627,493	)
Net property and equipment		8,104,670			8,011,625
Derivative assets		1,245			29
Goodwill		1,236,318			1,236,318
Other assets		241,794			252,339
Total assets	$	10,342,062		$	10,184,424
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities	$	359,141		$	429,336
Oil and gas production payable		196,622			197,092
Derivative liabilities		41,972			26,523
Current maturities of long-term debt		8,853			8,316
Total current liabilities		606,588			661,267
Long-term liabilities
Long-term debt, net of current portion		2,727,700			2,669,729
Asset retirement obligations		81,935			88,726
Derivative liabilities		22,013			18,872
Deferred taxes		1,953,253			1,918,576
Other liabilities		22,131			20,756
Total long-term liabilities		4,807,032			4,716,659
Commitments and contingencies (Note 6)
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; 404,722,399 and 402,946,070 shares issued, respectively		405			403
Paid-in capital in excess of par		3,102,617			3,090,374
Retained earnings		2,022,942			1,909,475
Accumulated other comprehensive loss		(400	)		(418	)
Treasury stock, at cost, 14,146,005 and 13,965,673 shares, respectively		(197,122	)		(193,336	)
Total stockholders' equity		4,928,442			4,806,498
Total liabilities and stockholders' equity	$	10,342,062		$	10,184,424

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
	March 31,
	2012		2011
Revenues and other income
Oil, natural gas, and related product sales	$	633,501	$	506,192
CO2 sales and transportation fees		6,795		4,924
Interest income and other income		4,820		3,049
Total revenues and other income		645,116		514,165
Expenses
Lease operating expenses		137,964		123,797
Marketing expenses		10,830		5,303
CO2 discovery and operating expenses		6,205		1,946
Taxes other than income		43,694		32,483
General and administrative		36,607		42,319
Interest, net of amounts capitalized of $19,445 and $10,957, respectively		36,314		48,777
Depletion, depreciation, and amortization		120,895		93,594
Derivatives expense		45,275		170,750
Loss on early extinguishment of debt		—		15,783
Impairment of assets		17,300		—
Other expenses		10,720		2,359
Total expenses		465,804		537,111
Income (loss) before income taxes		179,312		(22,946	)
Income tax provision (benefit)
Current income taxes		28,708		(848	)
Deferred income taxes		37,137		(7,908	)
Net income (loss)	$	113,467	$	(14,190	)
Net income (loss) per common share – basic	$	0.29	$	(0.04	)
Net income (loss) per common share – diluted	$	0.29	$	(0.04	)
Weighted average common shares outstanding
Basic		386,367		397,386
Diluted		390,943		397,386

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
	March 31,
	2012		2011
Net income (loss)	$	113,467	$	(14,190	)
Other comprehensive income, net of income tax:
Net unrealized gain on available-for-sale securities, net of tax of $2,550		—		4,163
Interest rate lock derivative contracts reclassified to income, net of tax of $11 and $11, respectively		18		17
Total other comprehensive income		18		4,180
Comprehensive income (loss)	$	113,485	$	(10,010	)

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)

	Three Months Ended
	March 31,
	2012			2011
Cash flows from operating activities
Net income (loss)	$	113,467		$	(14,190	)
Adjustments needed to reconcile to net cash flow provided by operations:
Depletion, depreciation, and amortization		120,895			93,594
Deferred income taxes		37,137			(7,908	)
Stock-based compensation		7,913			10,201
Noncash fair value derivative adjustments		44,113			172,367
Loss on early extinguishment of debt		—			15,783
Amortization of debt issuance costs and discounts		3,674			5,051
Impairment of assets		17,300			—
Other, net		7,725			(3,681	)
Changes in operating assets and liabilities:
Accrued production receivable		(8,863	)		(44,243	)
Trade and other receivables		9,162			(17,484	)
Other current and long-term assets		676			(8,449	)
Accounts payable and accrued liabilities		(32,861	)		(90,382	)
Oil and natural gas production payable		(470	)		18,770
Other liabilities		(28,214	)		(4,597	)
Net cash provided by operating activities		291,654			124,832
Cash flows from investing activities:
Oil and natural gas capital expenditures		(302,246	)		(190,296	)
Acquisitions of oil and natural gas properties		(592	)		(29,801	)
CO2 capital expenditures		(30,693	)		(27,150	)
Pipelines and plants capital expenditures		(60,441	)		(38,897	)
Purchases of other assets		(4,945	)		(12,770	)
Net proceeds from sales of oil and natural gas properties and equipment		166,703			11,989
Addition to restricted cash		(140,131	)		—
Proceeds from sale of short-term investments		83,545			—
Other		(83	)		1,882
Net cash used for investing activities		(288,883	)		(285,043	)
Cash flows from financing activities:
Bank repayments		(150,000	)		(130,000	)
Bank borrowings		210,000			130,000
Repayment of senior subordinated notes		—			(469,552	)
Premium paid on repayment of senior subordinated notes		—			(13,137	)
Net proceeds from issuance of senior subordinated notes		—			400,000
Net proceeds from issuance of common stock		3,949			5,253
Costs of debt financing		(11	)		(8,441	)
Other		(8,036	)		(7,924	)
Net cash provided by (used for) financing activities		55,902			(93,801	)
Net increase (decrease) in cash and cash equivalents		58,673			(254,012	)
Cash and cash equivalents at beginning of period		18,693			381,869
Cash and cash equivalents at end of period	$	77,366		$	127,857

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

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company.  We are the largest combined 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 our 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, 2011.  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2012, our consolidated results of operations for the three months ended March 31, 2012 and 2011, and our consolidated cash flows for the three months ended March 31, 2012 and 2011.  Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.  On the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011, “Taxes other than income” is a new line item and includes oil and natural gas ad valorem taxes, which were reclassified from “Lease operating expenses,” franchise taxes and property taxes on buildings, which were reclassified from “General and administrative,” oil and natural gas production taxes, which were reclassified from “Production taxes and marketing expenses” used in prior reports and CO2 property ad valorem and production taxes, which were classified from “CO2 discovery and operating expenses.”  Such reclassifications had no impact on our reported total expenses or net income.

Restricted Cash

Restricted cash consists of proceeds from the sale of oil and gas properties in February 2012 that are held by a qualified intermediary and are restricted for the pending acquisition of Thompson Field (see Note 8, Subsequent Events) to facilitate an anticipated like-kind exchange transaction.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to common 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 to net income and common shares of the potential dilution from stock options, stock appreciation rights (“SARs”), nonvested restricted stock, and nonvested performance equity awards.  For the three months ended March 31, 2012 and 2011, there were no adjustments to net income for purposes of calculating diluted net income per common share.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:

	Three Months Ended
	March 31,
In thousands	2012		2011
Basic weighted average common shares		386,367		397,386
Potentially dilutive securities:
Stock options and SARs		3,330		—
Performance equity awards		117		—
Restricted stock		1,129		—
Diluted weighted average common shares		390,943		397,386

Basic weighted average common shares excludes 3.9 million and 3.7 million shares of nonvested restricted stock during the three months ended March 31, 2012 and 2011, respectively.  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, the nonvested 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 antidilutive:

	Three Months Ended
	March 31,
In thousands	2012		2011
Stock options and SARs		3,179		12,641
Restricted stock		10		3,453
Total		3,189		16,094

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 December 31, 2011, 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 Encore Energy Partners LP to a subsidiary of Vanguard on December 31, 2010.  We received distributions of $1.8 million on the Vanguard common units we owned for the three months ended March 31, 2011, which are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations.  During January 2012, the Company sold its investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees.  The Company recognized a pretax loss on the sale of $3.1 million, which is included in “Other expenses” on our Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012.

Recently Adopted Accounting Pronouncements

Comprehensive Income.  In June 2011, the Financial Accounting Standards Board (“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 was effective for Denbury beginning January 1, 2012.  Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Fair Value.  In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”).  ASU 2011-04 amends the Financial Accounting Standards Board Codification (“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 was effective for Denbury beginning January 1, 2012.  The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures.  See Note 5, Fair Value Measurements.

Note 2. Acquisitions and Divestitures

Acquisitions

August 2011 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge

In August 2011, we acquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming.  Riley Ridge contains natural gas resources, as well as helium and CO2 resources.  The purchase included a 57.5% interest in a gas plant which will separate the helium and natural gas from the commingled gas stream, and interests in certain surrounding properties.  The purchase price was approximately $214.8 million after closing adjustments, including a $15.0 million deferred payment to be made at the time the Riley Ridge gas plant is operational and meets specific performance conditions.  The gas plant is currently undergoing readiness testing, and we expect it to become operational during the fourth quarter of 2012.

The August 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2011.  Because the Riley Ridge plant is not yet operational, current production at the field is negligible.  As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011.

Divestitures

On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million.  We entered into the sales agreement with a privately held entity in which a member of our Board of Directors serves as chairman of the board, in a sale for which there was a competing bid contained in a multi-property purchase proposal.  On February 29, 2012, we closed on the sale with net proceeds of $144.8 million, after preliminary closing adjustments.  The sale had an effective date of December 1, 2011 and consequently, operating net revenues after the effective date, net of capital expenditures, along with any other purchase price adjustments, were adjustments to the selling price.  We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Long-Term Debt

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

	March 31,			December 31,
In thousands	2012			2011
Bank Credit Facility	$	445,000		$	385,000
9½% Senior Subordinated Notes due 2016, including premium of $11,170 and $11,854, respectively		236,090			236,774
9¾% Senior Subordinated Notes due 2016, including discount of $16,783 and $17,854, respectively		409,567			408,496
8¼% Senior Subordinated Notes due 2020		996,273			996,273
6⅜% Senior Subordinated Notes due 2021		400,000			400,000
Other Subordinated Notes, including premium of $31 and $33, respectively		3,838			3,840
NEJD Pipeline financing		162,704			163,677
Free State Pipeline financing		79,189			79,597
Capital lease obligations		3,892			4,388
Total		2,736,553			2,678,045
Less current obligations		(8,853	)		(8,316	)
Long-term debt and capital lease obligations	$	2,727,700		$	2,669,729

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.  Certain of DRI’s subsidiaries guarantee our debt, and each such subsidiary guarantor is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees are full and unconditional and joint and several obligations of the subsidiary guarantors.

Bank Credit Facility

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 party thereto (as amended 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 of each year and upon requested special redeterminations.  The borrowing base is adjusted at the banks’ discretion and is based in part upon certain external factors over which we have no control.  The weighted average interest rate on borrowings under the credit facility, evidenced by the Bank Credit Agreement (the “Bank Credit Facility”) was 2.0% for the three months ended March 31, 2012.  We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base.  The Bank Credit Agreement is scheduled to mature in May 2016.

In April 2012, we entered into the Seventh Amendment to the Bank Credit Agreement (the “Bank Amendment”).  Under the Bank Amendment, we increased the amount of additional permitted subordinate debt (other than refinancing debt) from $300.0 million to $650.0 million.  At the same time, the banks reaffirmed Denbury’s borrowing base of $1.6 billion under the Bank Credit Facility until the next redetermination, which is scheduled to occur on or around November 1, 2012.

6⅜% Senior Subordinated Notes due 2021

In February 2011, we issued $400.0 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 $393.0 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Redemption of our 2013 and 2015 Notes

On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 7½% Senior Subordinated Notes due 2013 (“2013 Notes”) and all $300.0 million principal amount of our 7½% Senior Subordinated Notes due 2015 (“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 Notes 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 $15.8 million loss during the three months ended March 31, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

Note 4.  Derivative Instruments

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; 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” 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 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.  We only enter into commodity derivative contracts with parties that are lenders under our Bank Credit Agreement.

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

	Three Months Ended
	March 31,
In thousands	2012			2011
Oil
Payment on settlements of derivative contracts	$	8,230		$	5,028
Fair value adjustments to derivative contracts – expense		42,445			167,064
Total derivatives expense – oil		50,675			172,092
Natural Gas
Receipt on settlements of derivative contracts		(7,040	)		(6,616	)
Fair value adjustments to derivative contracts – expense		1,640			5,274
Total derivatives income – natural gas		(5,400	)		(1,342	)
Derivatives expense	$	45,275		$	170,750

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables present outstanding commodity derivative contracts with respect to future production as of March 31, 2012:

					Contract Prices(2)
		Type of					Weighted Average Price
Year	Months	Contract	Volume(1)		Range		Swap		Floor		Ceiling
Oil Contracts:
2012	Apr – June	Swap		625	$	80.28 – 81.75	$	81.04	$	—	$	—
		Collar		53,000		70.00 – 137.50		—		70.00		119.44
		Put		625		65.00 – 65.00		—		65.00		—
Total Apr – June 2012				54,250
July – Sept		Swap		625	$	80.28 – 81.75	$	81.04	$	—	$	—
		Collar		53,000		80.00 – 140.65		—		80.00		128.57
		Put		625		65.00 – 65.00		—		65.00		—
Total July – Sept 2012				54,250
Oct – Dec		Swap		625	$	80.28 – 81.75	$	81.04	$	—	$	—
		Collar		53,000		80.00 – 140.65		—		80.00		128.57
		Put		625		65.00 – 65.00		—		65.00		—
Total Oct – Dec 2012				54,250
2013	Jan – Mar	Swap		—	$	—	$	—	$	—	$	—
		Collar		55,000		70.00 – 117.00		—		70.00		110.32
		Put		—		—		—		—		—
Total Jan – Mar 2013				55,000
Apr – June		Swap		—	$	—	$	—	$	—	$	—
		Collar		50,000		75.00 – 124.20		—		75.00		116.92
		Put		—		—		—		—		—
Total Apr – June 2013				50,000
July – Sept		Swap		—	$	—	$	—	$	—	$	—
		Collar		50,000		75.00 – 133.10		—		75.00		122.14
		Put		—		—		—		—		—
Total July – Sept 2013				50,000
Oct – Dec		Swap		—	$	—	$	—	$	—	$	—
		Collar		18,000		80.00 – 127.50		—		80.00		126.63
		Put		—		—		—		—		—
Total Oct – Dec 2013				18,000

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

					Contract Prices(2)
		Type of					Weighted Average Price
Year	Months	Contract	Volume(1)		Range		Swap		Floor		Ceiling
Natural Gas Contracts:
2012	Apr – Dec	Swap		20,000	$	6.30 – 6.85	$	6.53	$	—	$	—
		Collar		—		—		—		—		—
		Put		—		—		—		—		—
Total Apr – Dec 2012				20,000

(1)	Contract volumes are stated in BBl/d and MMBtu/d for oil and natural gas contracts, respectively.
(2)	Contract prices are stated in $/BBl and $/MMBtu for oil and natural gas contracts, respectively.

Additional Disclosures about Derivative Instruments

At March 31, 2012 and December 31, 2011, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

					Estimated Fair Value
					Asset (Liability)
In thousands					March 31,		December 31,
Type of Contract				Balance Sheet Location	2012		2011
Derivatives not designated as hedging instruments:
	Derivative asset
		Crude oil contracts		Derivative assets – current	$	705	$	23,452
		Natural gas contracts		Derivative assets – current		22,310		23,950
		Crude oil contracts		Derivative assets – long-term		1,245		29
	Derivative liability
		Crude oil contracts		Derivative liabilities – current		(40,212)		(22,610)
		Deferred premiums(1)		Derivative liabilities – current		(1,760)		(3,913)
		Crude oil contracts		Derivative liabilities – long-term		(22,013)		(18,702)
		Deferred premiums(1)		Derivative liabilities – long-term		—		(170)
			Total derivatives not designated as hedging instruments		$	(39,725)	$	2,036

(1) Deferred premiums payable relate to various oil and natural gas floor contracts and are payable on a monthly basis through January 2013.

Note 5.  Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  We are able to classify fair value balances based on the observability of those inputs.  The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are as follows:

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

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.  The Company’s costless-collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

• Level 3 – Pricing inputs include significant inputs that are generally less observable 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 (i.e., Houston ship channel).  The Company’s basis swaps are estimated using discounted cash flow calculations based upon forward commodity price curves.  Significant increases or decreases in forward commodity price curves would result in a significantly higher or lower fair value measurement.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and Denbury’s credit quality for liability positions.  Denbury uses 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
March 31, 2012
Assets
Oil and natural gas derivative contracts	$	—	$	1,950		$	22,310	$	24,260
Liabilities
Oil and natural gas derivative contracts		—		(62,225	)		—		(62,225	)
Total	$	—	$	(60,275	)	$	22,310	$	(37,965	)
December 31, 2011
Assets
Short-term investments	$	86,682	$	—		$	—	$	86,682
Oil and natural gas derivative contracts		—		23,481			23,950		47,431
Liabilities
Oil and natural gas derivative contracts		—		(41,312	)		—		(41,312	)
Total	$	86,682	$	(17,831	)	$	23,950	$	92,801

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

Level 3 Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table summarizes the changes in the fair value of our Level 3 assets for the three months ended March 31, 2012 and 2011:

	Three Months Ended
	March 31,
In thousands	2012			2011
Balance, beginning of period	$	23,950		$	16,478
Unrealized gains on commodity derivative contracts included in earnings		5,400			310
Payments on settlement of commodity derivative contracts		(7,040	)		(1,442	)
Balance, end of period	$	22,310		$	15,346

We utilize an income approach to value our natural gas swap arrangements, generally the industry standard valuation technique for a commodity swap contract.  We obtain and ensure the appropriateness of the natural gas forward pricing curve, the most significant input to the calculation, and the fair value estimate is prepared and reviewed on a quarterly basis.

The following table details fair value inputs related to our level 3 financial measurements:

In thousands	Fair Value at 3/31/2012		Valuation Technique(s)	Unobservable Input	Range
Oil and natural gas derivative contracts	$	22,310	Discounted Cash Flow	Forward commodity price curve	(a)

(a) The derivative instruments detailed in this category include non-exchange-traded natural gas derivatives swaps that are valued based on regional pricing other than NYMEX.  The regional pricing sources utilized for these instruments include the following (forward pricing ranges represent the high and low price expected to be received within the settlement period):

Pricing Index	Settlement Period	Forward Pricing Range
TETCO M1	4/1/2012 – 12/31/2012	$2.09/MMBtu – $3.21/MMBtu
Houston Ship Channel	4/1/2012 – 12/31/2012	$2.06/MMBtu – $3.09/MMBtu
Natural Gas – Midcontinent	4/1/2012 – 12/31/2012	$1.98/MMBtu – $3.05/MMBtu

- 15 -

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

As of December 31, 2011, we had invested a total of $13.8 million in the preferred stock of Faustina Hydrogen Products LLC, a company created to develop a proposed gasification plant from which CO2 would be produced as a byproduct and used by Denbury in its tertiary oil operations.  The investment was recorded at cost, together with a $1.3 million receivable for accrued dividends receivable.  The developer of the proposed plant was soliciting other potential investors for the project, and as of December 31, 2011, a third-party was actively engaged in due diligence.  During 2012, a key investor and participant in the project announced its intent to abandon its investment in the proposed plant.  As a result, due diligence by the potential third party investor ceased.  Absent the key investor, we believe it is unlikely the plant will be constructed and therefore, it is also unlikely our investment will generate future cash flows.  Accordingly, we recorded a $15.1 million impairment charge for this investment during the first quarter of 2012, which is classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statements of Operations.  The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset.  These inputs are unobservable within the marketplace and therefore considered level 3 within the fair value hierarchy.  However, as there are currently no expected future cash flows associated with the plant, the fair value was determined to be $0.

Other Fair Value Measurements

The carrying value of our Bank Credit Facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.  The fair values of our senior subordinated notes are based on quoted market prices.  The estimated fair value of our senior subordinated notes as of March 31, 2012 and December 31, 2011 is $2,255.5 million and $2,253.2 million, respectively.  The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets).  We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 6. Commitments and Contingencies

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

Note 7. Related Party

During the first quarter of 2012, we purchased and marketed $1.2 million of oil produced by a privately-held entity of which a member of our Board of Directors serves as chairman of the board.  The oil purchased under this agreement is related to the non-core assets in central and southern Mississippi and in southern Louisiana (see further discussion in Note 2, Acquisitions and Divestitures) sold to this same entity.  We are under no obligation to purchase oil under this agreement.

In addition, during the first quarter of 2012, we entered into a sublease of excess office space at our former corporate headquarters with the same privately-held entity.  The sublease provides for payment of $2.4 million in lease rentals to us over the lease term, which expires on July 31, 2016.  During the first quarter of 2012, we recorded $27 thousand in lease income related to the new sublease arrangement, which is classified as “Interest income and other income” in the Unaudited Condensed Consolidated Statements of Operations.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. Subsequent Events

Sale of Non-Core Assets

On April 11, 2012, we announced that we had entered into an agreement and closed on the sale of certain non-operated assets in the Paradox Basin of Utah for $75 million.  The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million.  Preliminary closing adjustments include operating net revenues after January 1, 2012, net of capital expenditures, along with other purchase price adjustments.

Amendment to Bank Credit Agreement

During April 2012, we entered into an amendment to our Bank Credit Agreement (see Note 3, Long-Term Debt).

Pending Acquisition of Thompson Field

In April 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash.  Under the agreement, the seller will hold approximately a 5% net revenue interest beginning when average monthly tertiary oil production exceeds 3,000 Bbls/d.  Thompson Field is a significant potential tertiary oil flood located approximately 18 miles west of our Hastings Field, our most recent CO2 flood.  The acquisition is expected to close in June 2012.

- 17 -

Denbury Resources Inc.

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

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.  Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Information at the end of this Item 2 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 combined 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.

Operating Highlights

We recognized net income of $113.5 million, or $0.29 per basic common share, during the first quarter of 2012 compared to a net loss of $14.2 million, or $0.04 per basic common share, during the first quarter of 2011.  This increase in net income between the two periods is primarily attributable to:

·   an increase in oil and natural gas revenues of $127.3 million resulting from increased production ($69.4 million) and higher realized commodity prices ($57.9 million); and

·   a decrease in expenses of $71.3 million, the largest of which was a reduction of the non-cash loss in the fair value of the Company’s commodity derivative contracts of $128.3 million, principally due to the change in NYMEX oil futures prices relative to our derivative contracts in place during each period, offset in part by other expense increases.

During the first quarter of 2012, our oil and natural gas production, which was 93% oil, averaged 71,532 BOE/d compared to 63,604 BOE/d produced during the first quarter of 2011.  This 12% increase in production is primarily attributable to increases in our Bakken and tertiary oil production, partially offset by normal declines in most of our other non-tertiary properties.  After adjusting quarterly production in both periods to exclude production from non-core properties which were sold in 2012 (see Sale of Non-Core Assets below), continuing production in the first quarter of 2012 increased 14% over production in the comparable prior year quarter and 7% sequentially over levels in the fourth quarter of 2011.  Our tertiary oil production averaged 33,257 Bbls/d during the first quarter of 2012, an increase of 8% over the 30,825 Bbls/d produced during the first quarter of 2011 and 7% over fourth quarter 2011 levels.  Our Bakken oil production averaged 15,114 BOE/d during the first quarter of 2012, an increase of 164% over production of 5,728 BOE/d during the first quarter of 2011, and 29% over levels in the fourth quarter of 2011.  See Results of Operations — CO2 Operations and Results of Operations — Operating Results — Production for more information.

Oil prices during the first quarter of 2012 were considerably higher than prices during the first quarter of 2011, with average NYMEX oil prices averaging $102.89 per Bbl in the first quarter of 2012, compared to average NYMEX prices of $94.26 per Bbl during the first quarter of 2011.  Our average realized oil price received per barrel, excluding the impact of commodity derivative contracts, was $102.52 per Bbl during the first quarter of 2012, compared to $93.67 per Bbl during the first quarter of 2011, a 9% increase between the comparative periods.  See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information on our oil prices received and differentials to NYMEX prices.

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Denbury Resources Inc.

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

Sale of Investment in Vanguard Natural Resources LLC

On January 19, 2012, we sold our investment in Vanguard Natural Resources LLC (“Vanguard”) common units for cash consideration of $83.5 million, net of related transaction fees. The investment was originally acquired as partial consideration for the sale of our interests in Encore Energy Partners LP on December 31, 2010.  In connection with the sale, during the first quarter of 2012 we recorded a pretax $3.1 million loss which is classified as “Other expenses” in the Unaudited Condensed Consolidated Statements of Operations.   The $3.1 million loss represents the difference between the net proceeds received from the sale and the carrying amount of the investment at December 31, 2011.

Sale of Non-Core Assets

On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155 million.  On February 29, 2012, we closed the sale for net proceeds of $144.8 million, after preliminary closing adjustments.  The sale had an effective date of December 1, 2011 and consequently operating net revenues after December 1, 2011, net of capital expenditures, along with any other purchase price adjustments, reduced the selling price.  We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

On April 11, 2012, we announced that we had entered into an agreement and closed the sale of non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah for $75 million.  The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million.

Addition of Proved Oil and Natural Gas Reserves

During the first quarter of 2012, we added 18.3 MMBOE of estimated proved reserves, including 14.0 MMBOE at Oyster Bayou Field based on the field’s recent response to CO2 injections, and 4.3 MMBOE due to further development in the Bakken.  These increases were partially offset by the disposition of 6.6 MMBOE of reserves associated with certain non-core Gulf Coast assets we sold in February 2012, as discussed above.

Pending Acquisition of Thompson Field

On April 24, 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash.  Under the agreement, the seller will hold approximately a 5% net revenue interest when average monthly tertiary oil production exceeds 3,000 Bbls/d.  Thompson Field is a significant potential tertiary oil flood and is located approximately 18 miles west of our Hastings Field.  Net to Denbury’s interest, Thompson Field is producing approximately 2,200 Bbls/d of oil, roughly equivalent to the daily production volumes of our non-core assets divested to date in 2012, as discussed above, all of which is non-tertiary production.  The sale has an effective date of June 1, 2012 and is expected to close in June 2012.

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Denbury Resources Inc.

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

Capital Resources and Liquidity

We recently increased our projected 2012 capital budget from $1.35 billion to $1.5 billion based on higher than previously estimated cash flows as a result of better than expected commodity prices and production.  We allocated $80 million of our capital budget to further develop the Bakken, $65 million to tertiary oilfield expenditures (primarily in the Hastings and Bell Creek fields) and the remainder to other capital spending projects.  Our capital budget of $1.5 billion excludes estimated equipment leases ($75 million), acquisitions, capitalized interest and start-up costs associated with our new tertiary floods.  Our current 2012 capital budget includes the following:

·   $430 million allocated for tertiary oil field expenditures;

·   $480 million for development of our Bakken properties;

·   $290 million for pipeline construction;

·   $200 million to be spent on CO2sources; and

·   $100 million to be spent in all other areas.

Based on oil and natural gas prices in early May 2012 and our current production forecasts, we estimate that our 2012 capital budget (including capitalized interest and tertiary start-up costs) will be approximately $100 to $200 million greater than our 2012 anticipated cash flow from operations.  We plan to fund any shortfall between our cash flow from operations and our capital spending with our asset sales and borrowings under our Bank Credit Facility.

During the first three months of 2012, we incurred capital expenditures of approximately $319.8 million, net of equipment lease recoveries of $21.0 million.  Additionally, we have capitalized interest and tertiary start-up costs which are not included in the above mentioned amounts.  See additional detail on our expenditures in the table below.

During the first four months of 2012, we received net proceeds from non-core oil and natural gas asset divestitures of $217.2 million ($144.8 million at March 31, 2012 and $72.4 million during April 2012), $212.5 million of which are being held by a qualified intermediary to facilitate an anticipated like-kind exchange transaction.  We plan to use these proceeds, together with borrowings under our Bank Credit Facility, to fund the $360 million acquisition of Thompson Field, which is expected to close in early June 2012.  See Sale of Non-Core Assets and Pending Acquisition of Thompson Field discussed above.  In structuring these transactions as a like-kind exchange for income tax purposes, we anticipate deferral of a majority of the taxable gain recognized on the sale of the non-core assets.  Such amounts are classified as “Restricted cash” on the Unaudited Condensed Consolidated Balance Sheet.

In October 2011, we commenced a share repurchase program for up to $500 million of Denbury common stock.  To date we have only repurchased $195.2 million (all during the fourth quarter of 2011).  Any further share repurchases during 2012 will be determined based on various parameters; therefore, it is uncertain whether or not we will make additional share repurchases of Denbury common stock under this program in the remainder of 2012.

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 reduce our anticipated production levels in future years.  For 2012 and certain future years, we have contracted for certain capital expenditures; therefore, we cannot eliminate all of our capital commitments without penalties (refer to Management’s Discussion and Analysis – Capital Resources and Liquidity – Off-Balance Sheet Arrangements — Commitments and Obligations in the Form 10-K).  In addition to the potential flexibility in our capital spending plans, as of March 31, 2012, we had approximately $1.2 billion of unused liquidity under our Bank Credit Facility and have oil price floors in place through 2013 (see Note 4, Derivative Instruments, 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.  Also, we currently believe we could significantly expand our borrowing base beyond the current $1.6 billion if we desired to do so.

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Denbury Resources Inc.

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

Capital Expenditure Summary

The following table of capital expenditures includes accrued capital for the three months ended March 31, 2012 and 2011:

	Three Months Ended
	March 31,
In thousands	2012			2011
Capital expenditures by project:
Tertiary oil fields	$	113,578		$	100,984
Bakken		122,500			61,358
CO2 pipelines		14,151			3,497
CO2 properties		18,161			20,306
Other areas		72,373			46,310
Capital expenditures before acquisitions and capitalized interest		340,763			232,455
Less: recoveries from sale/leaseback transactions		(21,002	)		(2,445	)
Net capital expenditures excluding acquisitions and capitalized interest		319,761			230,010
Acquisitions:
Property acquisitions		1,234			29,801
Capitalized interest		19,445			10,957
Capital expenditures, net of sale/leaseback transactions	$	340,440		$	270,768

Our capital expenditures for the first three months of 2012 were funded with $291.7 million of cash flow from operations and the remainder with borrowings under our Bank Credit Facility.  Our capital expenditures for the first three months of 2011 were funded with $124.8 million of cash flow from operations and the remainder with cash on hand at the beginning of the period.

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.

Our commitments and obligations consist of those detailed as of December 31, 2011 in the Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Off-Balance Sheet Arrangements – Commitments and Obligations.

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Denbury Resources Inc.

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

Results of Operations

CO2 Operations

Our focus on CO2operations is the primary strategy of our business and operations.  We believe there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this estimated potential in our Form 10-K 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 Form 10-K for further information regarding these matters.

During the first quarter of 2012, our CO2 production at Jackson Dome averaged 1,047 MMcf/d, compared to an average of 1,021 MMcf/d produced during the first quarter of 2011 and 1,024 MMcf/d produced during the fourth quarter of 2011.  We used 92% of this production, or 964 MMcf/d, in our tertiary operations during the first quarter of 2012, and sold the balance to our industrial customers or to Genesis Energy, L.P. 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 Form 10-K for further discussion of our CO2 delivery obligations.  We believe we have sufficient CO2reserves to develop our current Gulf Coast enhanced oil recovery program, and we continue to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome.  At December 31, 2011, our proven CO2 reserves at Jackson Dome were approximately 6.7 Tcf.

We spent approximately $0.28 per Mcf in operating expenses to produce our CO2 during the first quarter of 2012, which costs averaged $0.25 per Mcf during the first quarter of 2011 and the fourth quarter of 2011.  This increase in the rate from the prior year quarters is due primarily to increased CO2 royalty expense (which is tied to oil prices) and an increase in lease operating expense charges.

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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 barrel for each quarter in 2011 and the first quarter of 2012:

	Average Daily Production (Bbl/d)
	First		Second		Third		Fourth		First
	Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2011		2011		2011		2011		2012
Phase 1:
Brookhaven		3,664		3,213		3,030		3,121		3,014
McComb area		2,161		1,983		2,005		1,843		1,746
Mallalieu area		2,925		2,646		2,620		2,587		2,585
Other		3,290		3,196		2,879		2,749		2,500
Phase 2:
Heidelberg		3,374		3,548		3,141		3,728		3,583
Eucutta		3,247		3,114		2,985		3,139		3,090
Soso		2,582		2,317		2,331		2,162		2,063
Martinville		500		416		453		481		551
Phase 3:
Tinsley		6,567		6,990		7,075		6,338		7,297
Phase 4:
Cranfield		991		1,085		1,214		1,200		1,152
Phase 5:
Delhi		1,524		2,263		3,358		3,778		4,181
Phase 7:(1)
Hastings		—		—		—		—		618
Phase 8:
Oyster Bayou		—		—		—		18		877
Total tertiary oil production (Bbl/d)		30,825		30,771		31,091		31,144		33,257
Tertiary lease operating expense per Bbl	$	24.93	$	22.87	$	24.91	$	23.59	$	26.74

(1) As of March 31, 2012, we did not have any tertiary production from our fields in Phase 6, Citronelle Field, which will require an extension to the Free State CO2 Pipeline or another pipeline, depending on the ultimate CO2 source for this field, the timing of which is uncertain.

Oil production from our tertiary operations increased to an average of 33,257 Bbls/d during the first quarter of 2012, an 8% increase over our first quarter 2011 tertiary production levels, primarily due to production growth in response to continued expansion of the tertiary floods in the Heidelberg, Tinsley, Cranfield and Delhi Fields and production at our Oyster Bayou and Hastings CO2 fields, which two fields experienced their initial tertiary production response in late December 2011 and early January 2012, respectively.  Offsetting first quarter production gains were declines in our more mature Phase 1 and Phase 2 fields (except Heidelberg and Martinville).  Production during the first quarter of 2012 increased 2,113 Bbls/d compared to fourth quarter 2011 levels primarily due to production increases at Tinsley, Delhi, Oyster Bayou and Hastings fields.

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Denbury Resources Inc.

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

The production growth rate at a tertiary flood can vary from quarter to quarter as a tertiary field’s production may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume its growth as additional areas of the field are developed.  During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production.  We also find it difficult to precisely predict when any given well will respond to the injected CO2, as the CO2 seldom travels through the rock consistently due to heterogeneity in the oil-bearing formations.  We find all of these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the entire field is developed, albeit sometimes in inconsistent patterns.  At Heidelberg Field, during the second half of 2011 and the first quarter of 2012, we modified 39 wells and 18 wells, respectively, in order to address conformance issues (i.e., to control the flow of the CO2 to the desired geologic zone within the reservoir).  While tertiary production at Heidelberg Field decreased slightly during the first quarter of 2012 compared to levels in the fourth quarter of 2011, we are seeing improvement in the gas / oil ratio in West Heidelberg, an indication that the conformance is working and that we are contacting the oil with CO2.  At Tinsley Field, during the third quarter of 2011, we stopped CO2 injections in parts of the field in order to address issues with wells that were improperly plugged by prior operators.  Full CO2 injections resumed during the first quarter of 2012 in Tinsley Field, which has responded with a 15% increase in sequential quarter production.

During the first quarter of 2012, operating costs for our tertiary properties averaged $26.74 per Bbl, compared to our first quarter of 2011 average cost of $24.93 per Bbl and a fourth quarter of 2011 average cost of $23.59 per Bbl.  The per-barrel increase in the most recent quarter was primarily due to our new tertiary floods at Oyster Bayou and Hastings fields and higher CO2 injection costs resulting from increased CO2 injection volumes and higher oil prices, to which CO2 costs are partially tied.  During the first quarter of 2012, Oyster Bayou and Hastings Fields entered the production stage and, as a result, injection costs associated with this production began to be expensed (as compared to being capitalized when in the development phase).  These two new tertiary floods account for a significant portion of our overall higher per-barrel tertiary operating expenses in the first quarter of 2012 because of the relatively low production at these two new floods in relation to the operating costs being expensed at these fields.  For any specific field, we expect our tertiary lease operating expense per barrel to be high initially and then decrease as production increases, ultimately leveling off until production begins to decline in the later life of the field, when lease operating expense per barrel will again increase.

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Denbury Resources Inc.

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

Operating Results

Certain of our operating results and statistics for the first three months of 2012 and 2011 are included in the following table:

	Three Months Ended
	March 31,
In thousands, except per share and unit data	2012			2011
Operating results
Net income (loss)	$	113,467		$	(14,190	)
Net income (loss) per common share – basic		0.29			(0.04	)
Net income (loss) per common share – diluted		0.29			(0.04	)
Net cash provided by operating activities		291,654			124,832
Average daily production volumes
Bbls/d		66,857			58,460
Mcf/d		28,052			30,866
BOE/d(1)		71,532			63,604
Operating revenues
Oil sales	$	623,706		$	492,838
Natural gas sales		9,795			13,354
Total oil and natural gas sales	$	633,501		$	506,192
Commodity derivative contracts(2)
Cash receipt (payment) on settlement of commodity derivative contracts	$	(1,190	)	$	1,588
Non-cash fair value adjustment expense		(44,085	)		(172,338	)
Total expense from commodity derivative contracts	$	(45,275	)	$	(170,750	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	102.52		$	93.67
Natural gas price per Mcf		3.84			4.81
Unit prices – including impact of derivative settlements(2)
Oil price per Bbl	$	101.16		$	92.72
Natural gas price per Mcf		6.59			7.19
Oil and natural gas operating expenses
Lease operating expenses	$	137,964		$	123,797
Marketing expenses		10,830			5,303
Taxes other than income(3)		43,694			32,483
Oil and natural gas operating revenues and expenses per BOE(1)
Oil and natural gas revenues	$	97.32		$	88.42
Lease operating expenses		21.19			21.63
Marketing expenses		1.66			0.93
Taxes other than income		6.71			5.67
Non-tertiary CO2 revenues and expenses:
CO2 sales and transportation fees	$	6,795		$	4,924
CO2 discovery and operating expenses(4)		(6,205	)		(1,946	)
CO2 revenue and expenses, net	$	590		$	2,978

(1)	Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE").
(2)	See also Item 3. Quantitative and Qualitative Disclosures about Market Risk below for information concerning the Company's derivative transactions.

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Denbury Resources Inc.

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

(3)	Includes $2.6 million and $1.5 million of franchise taxes and property taxes on office buildings as of March 31, 2012 and 2011, respectively.
(4)	Includes $4.9 million of exploratory drilling costs during the three months ended March 31, 2012.  We incurred no exploratory drilling costs during the three months ended March 31, 2011.

Production

Average daily production by area for each of the four quarters of 2011 and for the first quarter of 2012 are shown below:

	Average Daily Production (BOE/d)
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		First Quarter
Operating Area	2011		2011		2011		2011		2012
Gulf Coast region:
Tertiary oil fields		30,825		30,771		31,091		31,144		33,257
Non-tertiary fields:
Mississippi		5,930		5,642		5,636		4,746		4,573
Texas		4,371		4,202		4,096		3,868		3,674
Louisiana		511		454		47		141		191
Alabama and other		1,020		1,079		1,064		1,031		1,090
Total Gulf Coast region		42,657		42,148		41,934		40,930		42,785
Rocky Mountain region:
Cedar Creek Anticline		9,163		8,925		8,930		8,858		8,496
Bakken		5,728		7,626		9,976		11,743		15,114
Bell Creek		890		936		889		840		859
Other		2,613		2,693		2,689		2,533		2,516
Total Rocky Mountain region		18,394		20,180		22,484		23,974		26,985
Total Continuing Production		61,051		62,328		64,418		64,904		69,770
Properties disposed or to be disposed:
Gulf Coast assets(1)		1,918		1,901		1,732		1,677		1,054
Paradox assets(2)		635		690		680		653		708
Total Production		63,604		64,919		66,830		67,234		71,532

(1)	Includes production from certain non-core Gulf Coast assets sold in late February 2012.
(2)	Includes production from certain non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah sold in April 2012.

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Denbury Resources Inc.

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

Continuing production during the three months ended March 31, 2012 was 69,770 BOE/d, a 14% increase over continuing production during the first three months of 2011.  These increases were primarily due to production increases from the Bakken and our tertiary oil fields (see a discussion of our tertiary operations in CO2 Operations above), offset by normal declines in most of our other non-tertiary properties.  Total production increased 12% between the first quarters of 2011 and 2012, and includes production related to certain non-core Gulf Coast assets sold in February 2012 and non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah sold in April 2012.  Our production from the Cedar Creek Anticline is on a general decline, but also reflects a larger decline in periods of increasing prices due to a net profits interest associated with this production; therefore, a portion of the decline in production at this field is related to the increase in oil prices during the last twelve months.

Production from our Bakken properties averaged 15,114 BOE/d in the first quarter of 2012, a 164% increase from first quarter 2011 levels and an increase of 29% compared to fourth quarter 2011 production levels.  The production increases in the Bakken are due to the acceleration of our drilling activities in the area in 2011.  During 2011, we operated as many as seven drilling rigs in the Bakken, decreasing to six operated drilling rigs by the end of 2011.  We plan to reduce the rig count in the Bakken to four by mid-2012, which will likely begin to slow the rate of Bakken production growth.  During the first three months of 2012, we completed 13 operated wells in the Bakken.

Our production during the three months ended March 31, 2012 was 93% oil, which remained consistent with oil production of 92% during the three months ended March 31, 2011.

Oil and Natural Gas Revenues. Due to the increases in oil prices and production between the first three months of 2011 and 2012, our oil and natural gas revenues increased 25% during the first quarter of 2012 as compared to revenues in the first quarter of 2011.  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 March 31,
	2012 vs. 2011
In thousands	Increase in Revenues		Percentage Increase in Revenues
Change in oil and natural gas revenues due to:
Increase in production	$	69,422		14%
Increase in commodity prices		57,887		11%
Total increase in oil and natural gas revenues	$	127,309		25%

Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, 2012 and 2011:

	Three Months Ended
	March 31,
	2012			2011
Net Realized Prices:
Oil price per Bbl	$	102.52		$	93.67
Natural gas price per Mcf		3.84			4.81
Price per BOE		97.32			88.42
NYMEX Differentials:
Oil per Bbl	$	(0.37	)	$	(0.59	)
Natural gas per Mcf		1.32			0.61

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Denbury Resources Inc.

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

As reflected in the table above, our net realized oil prices increased in the first quarter of 2012 compared to those received during the first quarter of 2011, while oil differentials improved slightly between the two periods.  Company-wide oil price differentials in the first quarter of 2012 were $0.37 per Bbl below NYMEX, compared to an average differential of $0.59 per Bbl below NYMEX in the first quarter of 2011 and $9.14 per Bbl above NYMEX in the fourth quarter of 2011.  Our favorable NYMEX differential during the fourth quarter of 2011 was primarily due to the favorable differential for crude oil sold under Light Louisiana Sweet (“LLS”) index prices.  Prices received in a regional market can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors and location differentials.  NYMEX pricing, which has long been a benchmark price that reflects the economics in the U.S. midcontinent market, has been influenced in the recent past by significant increases in supply.  Alternatively, the LLS market is reflective of market economics in the Gulf Coast region, where both foreign and domestic oil is bought and sold, and correlates more closely to global oil prices.  During the first quarter of 2012, the Company sold approximately 40% of its crude oil at prices based on the LLS index price, approximately 20% at prices tied to a combination of the LLS index price and other indexes, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.  This LLS-to-NYMEX differential averaged a positive $12.55 per Bbl on a trade-month basis for the first quarter of 2012, compared to a positive $9.28 per Bbl differential in the first quarter of 2011 and a positive $23.36 per Bbl differential in the fourth quarter of 2011.  While this differential is significant in the pricing for our oil production, other factors may prevent us from realizing the full differential. As indicated by the above variations, the LLS-to-NYMEX differential is volatile and has been at historically high levels in recent periods, which may not continue.  The differential for oil production sold in the Bakken averaged $16.96 per Bbl below NYMEX in the first quarter of 2012, as compared to an average differential of $11.55 per Bbl below NYMEX in the first quarter of 2011 and $8.42 per Bbl below NYMEX in the fourth quarter of 2011.  Oil in the Bakken region sold at a significant discount during the first quarter of 2012 due to increased production in the area coupled with limited transportation infrastructure.

Commodity Derivative Contracts. The following tables summarize the impact our commodity derivative contracts had on our operating results for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012			2011			2012			2011			2012			2011
In thousands	Oil Derivative Contracts						Natural Gas Derivative Contracts						Total Commodity Derivative Contracts
Non-cash fair value loss	$	(42,445	)	$	(167,064	)	$	(1,640	)	$	(5,274	)	$	(44,085	)	$	(172,338	)
Cash settlement receipts (payments)		(8,230	)		(5,028	)		7,040			6,616			(1,190	)		1,588
Total	$	(50,675	)	$	(172,092	)	$	5,400		$	1,342		$	(45,275	)	$	(170,750	)

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. Lease operating expenses were $138.0 million during the three months ended March 31, 2012, an increase of $14.2 million (11%) from the same period in 2011.  This increase is primarily attributable to a 17% increase in our tertiary operating expenses, from $69.2 million to $80.9 million.  Lease operating expenses increased $13.8 million from $124.2 million during the fourth quarter of 2011, also due to increased lease operating expense on our tertiary properties.  See discussion of tertiary operating expenses above under CO2 Operations.  The increase in tertiary lease operating expense was partially offset in both comparative periods by lower lease operating expense on our non-tertiary properties, primarily due to the divestiture of certain non-core Gulf Coast properties during the first quarter of 2012.

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Denbury Resources Inc.

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

Lease operating expense averaged $21.19 per BOE for the three months ended March 31, 2012, compared to $21.63 per BOE for the same period in 2011 and $20.08 per BOE during the fourth quarter of 2011.  Lower non-tertiary operating expenses per BOE during both comparative periods is primarily due to increased Bakken production and the sale of our non-core Gulf Coast properties during the first quarter of 2012, which had a higher operating cost per BOE compared to the average of our other properties.  Our tertiary operating costs, which have historically been higher than our Company-wide operating costs, averaged $26.74 per Bbl during the three months ended March 31, 2012, compared to $24.93 per Bbl for the same period in 2011.  See CO2 Operations for a more detailed discussion.

Taxes other than income, which includes ad valorem, production and franchise taxes, averaged $6.71 per BOE for the three months ended March 31, 2012, compared to $5.67 per BOE for the same period in 2011.  The increase between periods is largely attributable to an increase in production taxes, which generally fluctuate in line with oil and natural gas revenues.

General and Administrative Expenses (“G&A”)

	Three Months Ended
	March 31,
In thousands, except per BOE data and employees	2012			2011
Administrative costs	$	74,060		$	67,328
Stock-based compensation		10,594			11,337
Operator labor and overhead recovery charges		(35,624	)		(29,269	)
Capitalized exploration and development costs		(12,423	)		(7,077	)
Net G&A expense	$	36,607		$	42,319
G&A per BOE:
Administrative costs, net	$	4.55		$	5.79
Stock-based compensation, net		1.07			1.60
Net G&A expense	$	5.62		$	7.39
Employees as of March 31		1,326			1,182

Net G&A expense during the first quarter of 2012 declined on both an absolute dollar and per BOE basis compared to levels in the first quarter of 2011, as higher administrative costs were more than offset by increased operator labor and overhead recovery charges and capitalized exploration and developments costs.  The 24% decrease in G&A per BOE between the two periods was further impacted by higher production.

Administrative costs increased $6.7 million (10%) during the first quarter of 2012 compared to the same period in 2011.  The increase between the comparative first quarters was primarily due to an increase in compensation-related costs due to an increase in headcount and salaries, which we consider necessary to remain competitive in our industry.  The increase in compensation expense was partially offset by a reduction in third-party professional services, corporate office expenses and insurance.

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well.  As a result of additional operated wells and drilling activities, additional tertiary operations and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 22% during the three months ended March 31, 2012 compared to the same period in 2011.  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

Interest and Financing Expenses
	Three Months Ended
	March 31,
In thousands, except per BOE data and interest rates	2012			2011
Cash interest expense	$	52,033		$	54,206
Non-cash interest expense		3,726			5,528
Less: capitalized interest		(19,445	)		(10,957	)
Interest expense	$	36,314		$	48,777
Interest income and other income	$	4,820		$	3,049
Net cash interest expense and other income per BOE (1)	$	4.27		$	7.10
Average debt outstanding	$	2,744,926		$	2,514,621
Average interest rate (2)		7.6	%		8.6	%

(1)	Cash interest expense less capitalized interest less interest and other income on BOE basis.
(2)	Includes commitment fees but excludes debt issue costs and amortization of discount and premium.

The increase in capitalized interest between the first quarters of 2011 and 2012 relates primarily to incremental capitalized interest on the Hastings and Conroe field CO2 floods, and the ongoing Riley Ridge and Greencore Pipeline construction.  We expect capitalization of interest to decrease later in 2012 due to the completion of currently ongoing development projects.

Depletion, Depreciation, and Amortization ("DD&A")
	Three Months Ended
	March 31,
In thousands, except per BOE data	2012		2011
Depletion and depreciation of oil and natural gas properties	$	107,055	$	82,086
Depletion and depreciation of CO2 properties		5,110		4,590
Asset retirement obligations		1,695		1,563
Depreciation of other fixed assets		7,035		5,355
Total DD&A	$	120,895	$	93,594
DD&A per BOE:
Oil and natural gas properties	$	16.71	$	14.61
CO2 and other fixed assets		1.86		1.74
Total DD&A cost per BOE	$	18.57	$	16.35

We adjust our DD&A rate each quarter for significant changes in our estimates of oil and natural gas reserves and costs.  As such, our DD&A rate has changed significantly over time, and it may continue to change in the future.  Depletion of oil and natural gas properties increased 30% on an absolute-dollar basis and 14% on a per-BOE basis during the first quarter of 2012 compared to the same period in 2011, primarily due to higher finding costs per barrel associated with the Bakken capital program and upward revisions in estimated future development costs, also primarily related to the Bakken.  The increase in DD&A on an absolute-dollar basis was further impacted by increases in production volumes.  Depletion of oil and natural gas properties increased 9% on an absolute-dollar basis between the fourth quarter of 2011 and the first quarter of 2012, primarily due to increased production volumes and higher future development costs related to Bakken wells, and increased slightly, by 3%, on a per-BOE basis.  The increase in depreciation of other fixed assets is primarily due to incremental pipeline depreciation.

During the first quarter of 2012 we recognized incremental reserves related to our tertiary production at Oyster Bayou Field and development in the Bakken.  See Overview – Addition of Proved Oil and Natural Gas Reviews above.  We currently expect to book initial proved tertiary reserves for our new tertiary flood at Hastings Field by the end of 2012.

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Denbury Resources Inc.

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

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 March 31, 2012; 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, in part, 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, as well as additional capital spent.

Impairment of Assets and Other Expenses

We recognized $17.3 million of impairment charges during the first quarter of 2012.  As of December 31, 2011, we had invested $13.8 million in a preferred interest in Faustina Hydrogen Products LLC, an entity created to develop a proposed plant from which we would offtake CO2.  The investment was recorded at cost, together with $1.3 million receivable for preferred distributions.  The developer of the proposed plant has been soliciting other potential investors for the project, and as of December 31, 2011, a third-party was actively engaged in due diligence.  During 2012, a key investor and participant in the project announced its intent to abandon its investment in the proposed plant.  As a result, due diligence by the potential third party investor ceased.  Absent the key investor, we do not believe our investment will generate future cash flows.  Accordingly, we recorded a $15.1 million impairment charge during the first quarter of 2012, which is classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statements of Operations.  The remaining $2.2 million asset impairment charge during the first quarter of 2012 relates to additional costs on a potential CO2 source that we do not believe will produce reserves in a quantity or at a cost that would benefit our tertiary oil operations.  Accordingly, we impaired the previously capitalized costs related to the development of the property.

Other expenses during the first quarter of 2012 includes a $3.1 million pretax loss on the sale of our investment in Vanguard common units (see First Quarter Operating Highlights above), a $3.9 million charge for our inability to deliver guaranteed quantities of helium under a helium supply arrangement with a third party and a $3.7 million charge to create an allowance for a potentially uncollectible loan receivable acquired in the Encore acquisition.  The helium supply agreement, which was assumed by the Company in connection with our purchase of the Riley Ridge Field, contemplated that the Riley Ridge plant would be operational in early 2012.  The plant is currently expected to start up during the fourth quarter of 2012.  Due to the delayed start up, we will be unable to meet our contractual commitment under the helium supply agreement.  We have recorded a charge for $3.9 million, which is our current estimate of the liability.  Our obligation under the contract could increase depending on the commencement of helium deliveries during 2012 and other factors; however, in accordance with the supply agreement, the obligation will not exceed $8.0 million during any given year.  Other expenses during the first quarter of 2011 included transaction and other costs related to our merger with Encore Acquisition Company.

Income Taxes
	Three Months Ended
	March 31,
In thousands, except per BOE amounts and tax rates	2012			2011
Current income tax expense (benefit)	$	28,708		$	(848	)
Deferred income tax expense (benefit)		37,137			(7,908	)
Total income tax expense (benefit)	$	65,845		$	(8,756	)
Average income tax expense (benefit) per BOE	$	10.12		$	(1.53	)
Effective tax rate		36.7	%		38.2	%

Our income taxes are based on an estimated statutory rate of approximately 38%.  Our effective tax rate for the first quarter of 2012 was slightly lower than our statutory rate, primarily due to the sale of our Vanguard common units in January 2012, which allowed us to utilize a larger amount of preferential tax benefits due to the higher taxable income from the sale, offset in part by nondeductible expenses.  Our effective tax rate for the first quarter of 2011 was higher than our statutory rate primarily due to nondeductible compensation.  The amount recorded as current income tax expense represents our federal alternative minimum taxes that we cannot offset with enhanced oil recovery credits and our state income taxes during the three months ended March 31, 2012 and 2011.

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Denbury Resources Inc.

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

As of December 31, 2011, we had an estimated $53.4 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2012 or future years.  The enhanced oil recovery credits do not begin to expire until 2023.  Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we do not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.

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
	March 31,
Per BOE data	2012			2011
Oil and natural gas revenues	$	97.32		$	88.42
Gain (loss) on settlements of derivative contracts		(0.18	)		0.28
Lease operating expenses		(21.19	)		(21.63	)
Marketing expenses		(1.66	)		(0.93	)
Production netback		74.29			66.14
CO2 sales, net of operating expenses		0.08			0.52
Taxes other than income(1)		(6.71	)		(5.67	)
General and administrative expenses		(5.62	)		(7.39	)
Net cash interest expense and other income		(4.27	)		(7.10	)
Other		(3.67	)		0.88
Changes in assets and liabilities relating to operations		(9.30	)		(25.57	)
Cash flow from operations		44.80			21.81
DD&A		(18.57	)		(16.35	)
Deferred income taxes		(5.71	)		1.38
Loss on early extinguishment of debt		—			(2.76	)
Non-cash commodity derivative adjustments		(6.78	)		(30.11	)
Impairment of assets		(2.66	)		—
Other non-cash items		6.35			23.55
Net income (loss)	$	17.43		$	(2.48	)

(1) "Taxes other than income" includes production taxes related to oil and natural gas production of $5.51 and $4.84, for the three months ended March 2012 and 2011, respectively.

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 the Form 10-K.

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Denbury Resources Inc.

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

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 the section “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, drilling activity or methods including the timing and location thereof, acquisition or disposition plans and proposals, development activities, timing of CO2 injections and initial production responses thereto, cost savings, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves, helium reserves, potential reserves, percentages of recoverable original oil in place, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices, cost and availability of equipment and services, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, prospective legislation affecting the oil and gas industry, 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, or are intended to 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 and adversely affect current plans, anticipated actions, the timing of such actions and the Company’s 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 or on behalf of the Company.  Among the factors that could cause actual results to differ materially are fluctuations of the prices received or demand for the Company’s 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; 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; general economic conditions; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings and public statements including, without limitation, the Form 10-K.

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Denbury Resources Inc.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Long-term Debt and Interest Rate Sensitivity

We finance some of our acquisitions and other expenditures with fixed and variable-rate debt.  Our Bank Credit Agreement and our senior subordinated notes do not have any triggers or covenants regarding our debt ratings with rating agencies.  Borrowings on our Bank Credit Facility, which bear interest at variable rates, expose us to market risk related to changes in interest rates.  As of March 31, 2012, our borrowings on our Bank Credit Facility were $445.0 million, with a weighted average interest rate of 2.0%.  At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense.

The following table presents the principal balances of our debt, by maturity date, as of March 31, 2012:

In thousands, except percentages	2014		2015		2016		2017		2020		2021
Variable rate debt:
Bank Credit Facility (weighted average interest rate of 2.00% at March 31, 2012)	$	—	$	—	$	445,000	$	—	$	—	$	—
Fixed rate debt:
9.5% Senior Subordinated Notes due 2016		—		—		224,920		—		—		—
9.75% Senior Subordinated Notes due 2016		—		—		426,350		—		—		—
8.25% Senior Subordinated Notes due 2020		—		—		—		—		996,273		—
6.375% Senior Subordinated Notes due 2021		—		—		—		—		—		400,000
Other Subordinated Notes		1,072		485		—		2,250		—		—

Commodity Derivative Contracts and Commodity Price Sensitivity

From time to time, we enter into oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production.  We do not hold or issue derivative financial instruments for trading purposes.  These contracts have consisted of price floors, collars and fixed price swaps.  The production that we hedge has varied from year to year, depending on our levels of debt and financial strength and expectation of future commodity prices.  We currently employ a strategy to hedge a portion of our forecasted production approximately a year and a half in the future from the current quarter, 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, to the Unaudited Condensed 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.  We only enter into commodity derivative contracts with parties that are lenders under our Bank Credit Facility.  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.

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Denbury Resources Inc.

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 March 31, 2012, our commodity derivative contracts were recorded at their fair value, which was a net liability of approximately $38.0 million (excluding $1.8 million of deferred premiums that Denbury is obligated to pay for its derivative contracts, which payments are not subject to changes in commodity prices), a change of approximately $44.1 million from the $6.1 million fair value net asset recorded at December 31, 2011 (excluding $4.1 million of deferred premiums).  This change is primarily related to changes in oil futures prices between December 31, 2011 and March 31, 2012.

Based on NYMEX crude oil and natural gas futures prices as of March 31, 2012, 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:

	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts			Natural Gas Derivative Contracts
Based on:
NYMEX futures prices as of March 31, 2012	$	(4,171	)	$	22,672
10% increase in prices		(34,882	)		21,353
10% decrease in prices		(2,229	)		23,999

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Denbury Resources Inc.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.  As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer.  Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2012, to ensure that information required to be disclosed in the reports the Company files and submits under the Exchange Act 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 its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, the Company determined that, during the first quarter of fiscal 2012, there were no changes in its internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

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Denbury Resources Inc.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item is incorporated by reference from the Form 10-K.

Item 1A. Risk Factors

Information with respect to the risk factors has been incorporated by reference from Item 1A of the Form 10-K.  There have been no material changes to the risk factors since the filing of the 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 first quarter of 2012, made solely in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights:

					Total Number of	Approximate Dollar
		Total			Shares Purchased	Value of Shares
		Number of	Average		as Part of Publicly	that May Yet Be
		Shares	Price Paid		Announced Plans or	Purchased Under the
Month		Purchased	per Share		Programs	Plans or Programs
January 2012		192,436	$	16.65	—	$	—
February 2012		28,938		19.69	—		—
March 2012		133,416		18.32	—		—
	Total	354,790		17.52	—	$	—

During the first quarter of 2012, the Company made no repurchases of common stock under its share repurchase program that began in October 2011.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity for more information.

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

None

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Denbury Resources Inc.

Item 6. Exhibits

Exhibit	Description
4(a)*	Seventh Amendment to Credit Agreement dated as of March 9, 2010, dated as of April 11, 2012, among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
10(a)* **	Form of 2012 Performance Stock Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)* **	Form of 2012 Performance Cash Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(c)* **	Form of 2012 TSR Performance Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
31(a)*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*	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.

** Compensation arrangements.

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Denbury Resources Inc.

SIGNATURES

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

	DENBURY RESOURCES INC.
Date: May 10, 2012	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President and Chief Financial Officer
Date: May 10, 2012	/s/ Alan Rhoades
	Alan Rhoades
	Vice President and Chief Accounting Officer

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EX-4.A

Exhibit 4(a)

SEVENTH AMENDMENT TO CREDIT AGREEMENT

This Seventh Amendment to Credit Agreement (this “Seventh Amendment”) is entered into as of April 11, 2012, by and among Denbury Resources Inc., a Delaware corporation (“Borrower”), JPMorgan Chase Bank, N.A., as Administrative Agent (“Administrative Agent”), and the financial institutions parties hereto as Banks (collectively, “Banks”, and each individually, a “Bank”).

W I T N E S S E T H

WHEREAS, Borrower, Administrative Agent, the other agents party thereto and Banks party thereto are parties to that certain Credit Agreement dated as of March 9, 2010 (as amended, the “Credit Agreement”) (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement, including, to the extent applicable, after giving effect to the amendments set forth in Section 1 of this Seventh Amendment);

WHEREAS, pursuant to the Credit Agreement, Banks have made a Revolving Loan to Borrower and provided certain other credit accommodations to Borrower; and

WHEREAS, Borrower has requested that (i) the Credit Agreement be amended to increase the permissible amount of Additional Permitted Subordinate Debt (other than Refinancing Debt) from $300,000,000 to $650,000,000 and (ii) the Borrowing Base be reaffirmed.

NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Administrative Agent and Banks hereby agree as follows:

Section 1.Seventh Amendment Effective Date Amendments.  In reliance on the representations, warranties, covenants and agreements contained in this Seventh Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement shall be amended effective as of the Seventh Amendment Effective Date (defined below) in the manner provided in this Section 1.

1.1Additional Definition.  Section 1.1 of the Credit Agreement shall be amended to add thereto in alphabetical order the following definition of “Seventh Amendment” which shall read in full as follows:

“Seventh Amendment” means that certain Seventh Amendment to Credit Agreement dated as of April 11, 2012 among Borrower, Administrative Agent and Banks party thereto.

1.2Amendment to Definition.  The definition of “Loan Papers” contained in Section 1.1 of the Credit Agreement shall be amended and restated in its entirety to read in full as follows:

“Loan Papers” means this Agreement, the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Sixth Amendment, the Seventh Amendment, the Notes, each Facility Guarantee which may now or hereafter be executed, each Borrower Pledge Agreement which may now or hereafter be executed, each Subsidiary Pledge Agreement which may now or hereafter be executed, all Mortgages now or at any time hereafter delivered pursuant to Section 5.1, and all other certificates, documents, or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time.

1.3Amendment to Section 2.13 of the Credit Agreement.  Section 2.13 of the Credit Agreement shall be amended and restated in its entirety to read in full as follows:

“Section 2.13   Automatic Reduction of Borrowing Base.  Simultaneously with the issuance or incurrence by any Credit Party of Additional Permitted Subordinate Debt (other than Refinancing Debt) on or after May 1, 2013 in accordance with Section 9.1(a)(ii)(A), the Borrowing Base shall be automatically reduced, without the need for any additional approval by Administrative Agent or Banks, by an amount equal to twenty-five percent (25%) of the principal amount of such Additional Permitted Subordinate Debt (other than Refinancing Debt) issued or incurred; provided, that Borrower shall notify Administrative Agent at least five (5) Domestic Business Days in advance of any such issuance or incurrence of Additional Permitted Subordinate Debt (other than Refinancing Debt).  Promptly following any such reduction in the Borrowing Base, Administrative Agent shall notify Borrower and Banks of the amount of the Borrowing Base as reduced, which Borrowing Base shall remain in effect for all purposes of this Agreement until the next Redetermination of the Borrowing Base in accordance with Article IV or any additional reduction of the Borrowing Base in accordance with this Section 2.13.”

1.4Amendment to Section 9.1(a)(ii)(A) of the Credit Agreement.  Section 9.1(a)(ii)(A) of the Credit Agreement shall be amended and restated in its entirety to read in full as follows:

“(A)           Additional Permitted Subordinate Debt (other than Refinancing Debt) may not exceed an aggregate principal amount outstanding at any one time of $650,000,000, and contemporaneously with any issuance or incurrence thereof with respect to Additional Permitted Subordinated Debt (other than Refinancing Debt) issued or incurred by any Credit Party on or after May 1, 2013(1) the Borrowing Base shall be automatically reduced pursuant to and in accordance with Section 2.13 and (2) Borrower shall make any mandatory prepayment required by with Section 2.6(b), if applicable;”

1.5Amendment to Section 9.1(d)(ii)(B) of the Credit Agreement.  The reference to “$300,000,000” set forth in clause (d)(ii)(B) is deleted and replaced with a reference to “$650,000,000”.

Section 2.Reaffirmation of Borrowing Base.  In reliance on the representations, warranties, covenants and agreements contained in this Seventh Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Borrowing Base shall be reaffirmed at $1,600,000,000 as of the Seventh Amendment Effective Date, and shall remain at $1,600,000,000 until the next Redetermination Date.  Borrower and Banks agree that the Redetermination provided for in this Section 2 shall be the May 1, 2012 Scheduled Redetermination and shall not be construed or deemed to be a Special Redetermination for purposes of Section 4.3 of the Credit Agreement.

Section 3.Conditions Precedent to Seventh Amendment Effective Date Amendments.  The amendments contained in Section 1 and the reaffirmation of the Borrowing Base contained in Section 2 hereof shall be effective on the date that each of the following conditions precedent is satisfied (the “Seventh Amendment Effective Date”):

3.1Counterparts.  Administrative Agent shall have received counterparts hereof duly executed by Borrower and the Required Banks and acknowledged by each Restricted Subsidiary (or, in the case of any party as to which an executed counterpart shall not have been received, telegraphic, telecopy, or other written confirmation from such party of execution of a counterpart hereof by such party).

3.2No Default; No Borrowing Base Deficiency.  No Default or Event of Default shall have occurred which is continuing, and no Borrowing Base Deficiency then exists.

3.3Other Documents.  Administrative Agent shall have been provided with such documents, instruments and agreements, and Borrower shall have taken such actions, in each case as Administrative Agent may reasonably require in connection with this Seventh Amendment and the transactions contemplated hereby.

Section 4.Representations and Warranties.  To induce Banks and Administrative Agent to enter into this Seventh Amendment, Borrower hereby represents and warrants to Banks and Administrative Agent as follows on the Seventh Amendment Effective Date:

4.1Reaffirm Existing Representations and Warranties.  Each representation and warranty of Borrower contained in the Credit Agreement and the other Loan Papers is true and correct in all material respects on the date hereof and will be true and correct in all material respects after giving effect to the amendments set forth in Section 1 hereof, except that any representation or warranty that is qualified by “material” or “Material Adverse Effect” references therein shall be true and correct in all respects.

4.2Due Authorization; No Conflict.  The execution, delivery and performance by Borrower of this Seventh Amendment are within Borrower’s corporate or organizational powers, have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any Material Agreement binding upon Borrower or any other Credit Party or result in the creation or imposition of any Lien upon any of the assets of Borrower or any other Credit Party other than Liens securing the Obligations.

4.3Validity and Enforceability.  This Seventh Amendment constitutes the valid and binding obligation of Borrower enforceable in accordance with its terms, except as (a) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (b) the availability of equitable remedies may be limited by equitable principles of general application.

4.4No Defense.  Borrower acknowledges that Borrower has no defense to (a) Borrower’s obligation to pay the Obligations when due, or (b) the validity, enforceability or binding effect against Borrower of the Credit Agreement or any of the other Loan Papers or any Liens intended to be created thereby.

Section 5.Miscellaneous.

5.1No Waivers.  No failure or delay on the part of Administrative Agent or Banks to exercise any right or remedy under the Credit Agreement, any other Loan Papers or applicable law shall operate as a waiver thereof, nor shall any single or partial exercise of any right or remedy preclude any other or further exercise of any right or remedy, all of which are cumulative and may be exercised without notice except to the extent notice is expressly required (and has not been waived) under the Credit Agreement, the other Loan Papers and applicable law.

5.2Reaffirmation of Loan Papers.  Any and all of the terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect.  The amendments contemplated hereby shall not limit or impair any Liens securing the Obligations, each of which are hereby ratified, affirmed and extended to secure the Obligations as they may be increased pursuant hereto.

5.3Legal Expenses.  Borrower hereby agrees to pay on demand all reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this Seventh Amendment and all related documents.

5.4Parties in Interest.  All of the terms and provisions of this Seventh Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.

5.5Counterparts.  This Seventh Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Seventh Amendment until Borrower, the Required Banks and each Restricted Subsidiary have executed a counterpart.  Facsimiles shall be effective as originals.

5.6Complete Agreement.  THIS SEVENTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES.

5.7Headings.  The headings, captions and arrangements used in this Seventh Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Seventh Amendment, nor affect the meaning thereof.

5.8Governing Law.  THIS SEVENTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[SIGNATURE PAGES FOLLOW]

IN WITNESS WHEREOF, the parties hereto have caused this Seventh Amendment to be duly executed by their respective authorized officers on the date and year first above written.

BORROWER:
DENBURY RESOURCES INC., a Delaware corporation
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

[Signature Page]

Seventh Amendment to Credit Agreement

Denbury Resources Inc.

Each of the undersigned (i) consent and agree to this Seventh Amendment, and (ii) agree that the Loan Papers to which it is a party shall remain in full force and effect and shall continue to be the legal, valid and binding obligation of such Person, enforceable against it in accordance with its terms.

DENBURY GATHERING & MARKETING INC., a Delaware corporation
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

DENBURY HOLDINGS INC., a Delaware corporation (f/k/a Denbury Encore Holdings Inc.)
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

DENBURY OPERATIONG COMPANY, a Delaware corporation (f/k/a EAP Properties, Inc. and successor-by-merger to a previous “Denbury Operating Company”)
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

DENBURY ONSHORE, LLC, a Delaware limited liability company
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

DENBURY PIPELINE HOLDINGS, LLC, a Delaware limited liability company
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

[Signature Page]

Seventh Amendment to Credit Agreement

Denbury Resources Inc.

DENBURY GREEN PIPELINE-TEXAS, LLC, a Delaware limited liability company
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

DENBURY GULF COAST PIPELINES, LLC, a Delaware limited liability company
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

GREENCORE PIPELINE COMPANY, LLC, a Delaware limited liability company
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

DENBURY AIR, LLC, a Delaware limited liability company (f/k/a EAP Operating, LLC)
By:	/s/ James S. Matthews
	James S. Matthews, Vice President and General Counsel

[Signature Page]

Seventh Amendment to Credit Agreement

Denbury Resources Inc.

ADMINISTRATIVE AGENT/BANK:
JPMORGAN CHASE BANK, N.A., As Administrative Agent and a Bank
By:	/s/ Mark E. Olson
	Mark E. Olson Authorized Officer

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
BANK OF AMERICA, N.A.
By:	/s/ Stephen J. Hoffman
Name:	Stephen J. Hofman
Title:	Managing Director

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
THE BANK OF NOVA SCOTIA
By:	/s/ John Frazell
Name:	John Frazell
Title:	Director

[Signature Page]

Seventh Amendment to Credit Agreement

Denbury Resources Inc.

BANKS:
CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH
By:	/s/ Bill O’Daly
Name:	Bill O’Daly
Title:	Director

By:	/s/ Michael D. Spaight
Name:	Michael D. Spaight
Title:	Associate

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
ROYAL BANK OF CANADA
By:	/s/ Jay T. Sartain
Name:	Jay T. Sartain
Title:	Authorized Signatory

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Seventh Amendment to Credit Agreement

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BANKS:
WELLS FARGO BANK, N.A.
By:	/s/ Thomas E. Stelmer, Jr.
Name:	Thomas E. Stelmer, Jr.
Title:	Vice President

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
UBS LOAN FINANCE, LLC
By:	/s/ Mary E. Evans
Name:	Mary E. Evans
Title:	Associate Director

By:	/s/ Irja R. Otsa
Name:	Irja R. Otsa
Title:	Associate Director

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
UNION BANK, N.A.
By:	/s/ David Carter
Name:	David Carter
Title:	Investment Banking Officer

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Seventh Amendment to Credit Agreement

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BANKS:
CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK (f/k/a CALYON NEW YORK BRANCH)
By:	/s/ Tom Byargeon
Name:	Tom Byargeon
Title:	Managing Director

By:	/s/ Sharada Manne
Name:	Sharada Manne
Title:	Managing Director

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
BANK OF SCOTLAND plc
By:	/s/ Julia R. Franklin
Name:	Julia R. Franklin
Title:	Vice President

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Seventh Amendment to Credit Agreement

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BANKS:
COMPASS BANK
By:	/s/ Dorothy Marchand
Name:	Dorothy Marchand
Title:	Senior Vice President

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Seventh Amendment to Credit Agreement

Denbury Resources Inc.

BANKS:
CAPITAL ONE NATIONAL ASSOCIATION, formerly known as Capital One, N.A.
By:	/s/ Peter Shen
Name:	Peter Shen
Title:	Vice President

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
COMERICA BANK
By:	/s/ James A. Morgan
Name:	James A. Morgan
Title:	Vice President

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Seventh Amendment to Credit Agreement

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BANKS:
ING CAPITAL LLC
By:	/s/ Juli Bieser
Name:	Juli Bieser
Title:	Director

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Seventh Amendment to Credit Agreement

Denbury Resources Inc.

BANKS:
SUNTRUST BANK
By:	/s/ Gregory C. Magnuson
Name:	Gregory C. Magnuson
Title:	Vice President

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Seventh Amendment to Credit Agreement

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BANKS:
CIBC, INC.
By:	/s/ Trudy Nelson
Name:	Trudy Nelson
Title:	Authorized Signatory

By:	/s/ Richard Antl
Name:	Richard Antl
Title:	Authorized Signatory

[Signature Page]

Seventh Amendment to Credit Agreement

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BANKS:
KEYBANK NATIONAL ASSOCIATION
By:	/s/ Craig Hanselman
Name:	Craig Hanselman
Title:	Vice President

[Signature Page]

Seventh Amendment to Credit Agreement

Denbury Resources Inc.

BANKS:
U.S. BANK NATIONAL ASSOCIATION
By:	/s/ Daria Mahoney
Name:	Daria Mahoney
Title:	Vice President

[Signature Page]

Seventh Amendment to Credit Agreement

Denbury Resources Inc.

BANKS:
SUMITOMO MITSUI BANKING CORPORATION
By:	/s/ Masakazu Hasegawa
Name:	Masakazu Hasegawa
Title:	Managing Director

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Seventh Amendment to Credit Agreement

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BANKS:
FIFTH THIRD BANK
By:	/s/ Matthew Lewis
Name:	Matthew Lewis
Title:	Vice President

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Seventh Amendment to Credit Agreement

Denbury Resources Inc.

BANKS:
GOLDMAN SACHS LENDING PARTNERS LLC
By:	/s/ Michelle Latzoni
Name:	Michelle Latzoni
Title:	Authorized Signatory

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Seventh Amendment to Credit Agreement

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EX-10.A

Exhibit 10(a)

Maximum Performance Shares

Date of Grant: January 6, 2012

2012 PERFORMANCE STOCK AWARD

2004 OMNIBUS STOCK AND INCENTIVE PLAN

FOR DENBURY RESOURCES INC.

PERFORMANCE STOCK AWARD (“Award”) made effective January 6, 2012 (“Date of Grant”) between Denbury Resources Inc. (the “Company”) and «Officer_Name» (“Holder”).

WHEREAS, Section 17 of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (“Plan”) authorizes the Committee to grant performance-based Awards;

WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn a maximum of

Performance Shares based on the performance factors set forth in this Award, and subject to all of the provisions, including without limitation the Vesting provisions, of the Plan and this Award;

WHEREAS, no Performance Shares will be issued or outstanding until their respective Vesting Dates or they become Retained Earned Shares; and

WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award.

NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:

1.      Performance Share Grant. The Company hereby grants Holder the right to earn, Vest in, and receive delivery of, on the Delivery Date up to Reserved Shares (“Performance Shares”) subject to the terms and conditions set forth in the Plan and in this Award.

2.      Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:

(a) “BOE” means Barrels of Oil Equivalent, and for all purposes hereof, will be calculated using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

(b) “Committee Percentage Point Reduction” means the number (if any) of Performance Percentage Points (not in excess of the Committee Percentage Point Reduction Limitation) by which the Committee reduces Holder’s Performance Percentage Points in accordance with Section 7 hereof.

(c) “Committee Percentage Point Reduction Limitation” means the lesser of (i) forty (40) Performance Percentage Points, and (ii) the product of (x) Holder’s Performance Percentage Points earned during the Performance Period as determined prior to the application of the Committee Percentage Point Reduction, multiplied by (y) twenty-five percent (25%).

(d) “Delivery Date” means the date on which Vested Earned Shares (other than Retained Earned Shares and Performance Shares delivered under 8(b)) are delivered to Holder, which shall be the Vesting Date, or as soon thereafter as practicable, but in no event later than 30 days after the Vesting Date.

(e) “Disability” means, without limitation, the same as it does in the Plan.

(f) “Earned Performance Shares” means the number of Performance Shares which are earned during the Performance Period as described and calculated in Section 8.

(g) “Fiscal Year” means the 12-month period adopted by the Company for financial reporting purposes.

(h) “Performance Measure” means, collectively, changes in amounts of oil and gas reserves, changes in production rates, and operating cost reductions, as determined based upon the (i) the Tertiary Oil Production Measure, (ii) the Corporate Production Measure, (iii) LOE per BOE Measure, and (iv) the Reserve Replacement Measure; provided, further, that when reference to a specific Performance Measure is intended, reference will be made to such specific Performance Measure.

(i) “Performance Period” means the period beginning on January 1, 2012, and ending on December 31, 2012.

(j) “Performance Percentage” means the excess of (i) Holder’s aggregate Performance Percentage Points, over (ii) the Committee Percentage Points Reduction, if any, determined as of the last day of the Performance Period.

(k) “Performance Percentage Points” means, collectively, the points, designated as Performance Percentage Points, earned with respect to each Performance Measure during Performance Period.

(l) “Performance Shares” means the number of Reserved Shares subject to this Award, as shown on the first page of this Award.

(m) “Post Separation Change in Control” means a Change in Control which follows Holder’s Separation, but results from the Commencement of a Change in Control that occurs prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change in Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates.

(n) “Target Performance Shares” means  of the Performance Shares, which is the number of Performance Shares which will be Earned Performance Shares if Holder’s Performance Percentage is 100%.

(o)      “Vesting Date” means March 31, 2013.

3.      Performance Percentage Points Earned With Respect To The Tertiary OilProduction Measure.

(a) Tertiary Production Based Performance Percentage Points. The Performance Percentage Points which will be credited to Holder with respect to the Tertiary Oil Production Measure are set forth in the following Chart based on the Average Annual Tertiary Production Percentage. The “Average Annual Tertiary Production Percentage” means the quotient (rounded to 3 decimal places and then expressed as a percentage) of (x) the Adjusted Tertiary Oil Production for such Fiscal Year, divided by (y) the Tertiary Oil Production Forecast for such Fiscal Year.

	Average Annual Tertiary Production Percentage	Performance Percentage Points
A.	107.2% or more	70
B.	104.3% to 107.1%	56
C.	100% to 104.2%	42
D.	95.7% to 99.9%	28
E.	Less than 95.7%	0

(b) Adjusted Tertiary Oil Production. For purposes of this Award, the “Adjusted Tertiary Oil Production” shall be equal to (i) the actual tertiary oil production of the Company for such Fiscal Year as reported in the Company’s Form 10-K, or if not specifically reported, then as determined by the Committee from the underlying documents, minus (ii) the tertiary oil production related to an oil property acquired during such Fiscal Year, such amount to be the lesser of (a) the actual tertiary oil production for such Fiscal Year from the acquired property or incremental property interest (if a material partial interest) or (b) the forecasted oil production related thereto for such Fiscal Year for the property before any improvements made by the Company following the acquisition of the property, plus (iii) that portion of the Tertiary Oil Production Forecast, as defined below which is related to any oil property disposed or sold during such Fiscal Year for the period during which the Company did not own the oil property.

(c) Tertiary Oil Production Forecast. For purposes of this Award, “Tertiary Oil Production Forecast” means for 2012, 34,500 barrels of oil per day.

4.      Performance Percentage Points Earned With Respect To The CorporateProduction Measure.

(a) Corporate Production Based Performance Percentage Points. The Performance Percentage Points which will be credited to Holder with respect to the Corporate Production Measure are set forth in the following Chart based on the Average Annual Corporate Production Percentage. The “Average Annual Corporate Production Percentage” means for such Fiscal Year, the quotient (rounded to 3 decimal places and then expressed as a percentage) of (x) the Adjusted Corporate Production of the Company for such Fiscal Year, divided by (y) the Corporate Production Forecast for such Fiscal Year.

	Average Annual Corporate Production Percentage	Performance Percentage Points
A.	106.2% or more	40
B.	103.4% to 106.1%	32
C.	100% to 103.3%	24
D.	96.6% to 99.9%	16
E.	Less than 96.6%	0

(b) Adjusted Corporate Production. For purposes of this Award, “Adjusted Corporate Production” means (i) the actual production of oil and natural gas (in BOEs) for the Fiscal Year as reported in the Company’s Form 10-K (“Corporate Production”), minus (ii) the oil and natural gas production (in BOEs) related to properties acquired during such Fiscal Year, such amount to be the lesser of (a) the actual oil and natural gas production (in BOEs) for such Fiscal Year from the acquired property or incremental property interest (if a partial interest) or (b) the forecasted oil and natural gas production (in BOEs) related thereto for such Fiscal Year for the property before any improvements made by the Company following the acquisition of the property, plus (iii) that portion of the Corporate Production Forecast, as defined below, which is related to any oil or natural gas property disposed or sold during such Fiscal Year for the period during which the Company did not own the property.

(c) Corporate Production Forecast. For purposes of this Award, “Corporate Production Forecast” means for 2012, 72,750 BOE per day.

5.      Performance Percentage Points Earned With Respect To Lease OperatingExpense (“LOE”) Per BOE Measure.

(a) “Actual-to-Budget” LOE Per BOE Measure Performance Percentage Points. The Performance Percentage Points which will be credited to Holder with respect to “Actual-to-Budget” LOE Per BOE Measure are set forth in the following Chart as compared to the various budgeted levels of LOE per BOE set forth in such Chart.

(b) “Actual LOE Per BOE” for such Fiscal Year means (x) the actual LOE for the Fiscal Year as reported in the Company’s Form 10-K for 2012 (less the cost for CO2 as per the Company’s detailed LOE analysis) minus total LOE (including cost for CO2) related to properties acquired during such Fiscal Year, plus for properties sold during such Fiscal Year, the originally budgeted LOE for that portion of such Fiscal Year during which the results of operations of such properties are not included in the Company’s financial results, divided by (y) the actual oil and natural gas production (in BOEs) for such Fiscal Year as reported in the Company’s Form 10-K for 2012, minus the actual oil and natural gas production (in BOEs) for such Fiscal Year from properties or incremental property interests (if a partial interest) acquired during such Fiscal Year, plus for properties sold during such Fiscal Year, the originally budgeted production for that portion of such Fiscal Year during which the results of operations of such properties are not included in the Company’s financial results.

(c) Performance Percentage Points. The Performance Percentage Points which will be awarded Holder for the Performance Period with respect to the LOE per BOE Measure will be calculated as of the last day of the Performance Period, and will be based on the levels of Actual LOE per BOE during the Fiscal Year as compared to the levels shown in the following Chart:

	Actual LOE Per BOE	Performance Percentage Points
A.	Less than $17.68	50
B.	$17.68 to $18.15	40
C.	$18.16 to $18.78	30
D.	$18.79 to $19.45	20
E.	Greater than $19.45	0

6.      Performance Percentage Points Earned With Respect To The ReserveReplacement Measure.

The Performance Percentage Points Holder will earn with respect to the Reserve Replacement Measure will be based on the Company’s Reserve Replacement Percentage for the entire Performance Period. “Reserve Replacement Percentage” means the quotient (rounded up to 3 decimal places and then expressed as a percentage) of (i) the Final Reserves less the Initial Reserves, divided by (ii) Total Production for the Company.

(a) Performance Percentage Points. The Performance Percentage Points which will be awarded Holder for the Performance Period with respect to the Reserve Replacement Measure are set forth in the following Chart:

	Reserve Replacement Percentage	Performance Percentage Points
A.	300% or more	40
B.	200% to 299%	32
C.	150% to 199%	24
D.	100% to 149%	16
E.	Less than 100%	0

(b) Initial Reserves. For purpose of this Award, “Initial Reserves” means the total Company proved reserve quantities as of December 31, 2011 expressed in BOEs as estimated by DeGolyer and MacNaughton, independent petroleum engineers and disclosed in the Company’s Form 10-K Report for 2011.

(c) Final Reserves. For purposes of this Award, “Final Reserves” means the sum of (i) the total Company proved reserve quantities on the last day of the Performance Period expressed in BOEs as estimated by DeGolyer and MacNaughton or the Company’s then current independent petroleum engineer, determined using the same price deck as was used by the Company in calculating the Initial Reserves, plus (ii) the Uneconomic Reserves, plus (iii) the Disposed Reserves, plus (iv) Total Production. The “Uneconomic Reserves” are those proved undeveloped reserves expressed in BOEs which were included in the Initial Reserves, but are not considered proved undeveloped reserves on the last day of the Performance Period solely because the price deck used to price oil and natural gas products and/or the prices used to estimate the capital costs required to develop the proved undeveloped reserves as of the last day of the Performance Period have changed from those used in the Initial Reserve report such that the extraction of such otherwise proved reserves is uneconomic (i.e. Uneconomic Reserves cannot be reserves excluded from the Final Reserves because drilling activity during the period changed the status or evaluation of the undeveloped reserves, or because the Company no longer holds the acreage or interest, or because factors other than commodity prices or changes in the estimated capital costs have made the project uneconomic). The “Disposed Reserves” are those proved reserves quantities expressed in BOEs which were sold during the Performance Period as reported as such in the Company’s Form 10-K SFAS 69 disclosures.

7.      Committee’s Reduction of Performance Percentage Points.

Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by written notice to Holder prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage Points by applying a Committee Percentage Point Reduction.

(a) Performance Percentage Points Reduction. The Committee will make its determination of the Committee Percentage Point Reduction amount (if any) based on the Committee’s subjective evaluation of Company performance with respect to each of the four Additional Committee Evaluation Factors listed in (b) below, which evaluation will determine the amount of the Performance Percentage Points reduction for each such Additional Committee Evaluation Factor based on the Chart below, and the sum of those reductions, but not in excess of the Committee Percentage Point Reduction Limitation, will be Committee Percentage Point Reduction for the Performance Period:

	Committee’s Determination of the Level of Performance With Respect to each Committee Evaluation Factor	Reduction in Performance Percentage Points
A.	Above Average	0
B.	Average	5
C.	Below Average	10

(b) For purposes of this Award, the “Additional Committee Evaluation Factors” (each of which may cause a reduction of up to 10 Performance Percentage Points) are:

(i)       the Company’s compliance with such corporate governance factors as the ability to obtain an unqualified auditors’ opinion on the Company’s financial statements contained in its Form 10-K for 2012, and avoid any financial restatements,

(ii)       the Company’s maintenance of a reasonable debt-to-capital and/or debt-to-cash flow ratio,

(iii)       the Company’s record as to health, safety and environmental compliance and results, and

(iv)       the increase in the net asset value per share of Company stock, determined after excluding the effects, to the extent reasonably practical, caused by fluctuations in commodity prices and capital and operating costs or other factors which are generally not controllable by the Company.

8.      Earning Performance Shares.

(a) Earned Performance Shares. The number of Earned Performance Shares shall be equal to the product of (i) the Target Performance Shares, multiplied by (ii) the Performance Percentage. Only whole shares will be issued to the Holder. The Committee will determine, and the Administrator will advise Holder, of Holder’s Performance Percentage as soon as reasonably possible after the last day of the Performance Period.

(b) Change in Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change in Control occurs during the Performance Period then, regardless of the Performance Percentage at the date of the Change in Control, Holder will be entitled to receive delivery of all of the Target Performance Shares (notwithstanding any provision hereof to the contrary, none of which Target Performance Shares will be retained by the Company other than as payment for withholding) as soon as reasonably possible following such Change in Control, but in no event later than the 15th day of the third month after the end of the calendar year in which such Change in Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Shares.

9.      Vesting (and Forfeiture) of Earned Performance Shares.

(a) No Separation Prior to the Vesting Date. If Holder does not Separate prior to the Vesting Date, Holder will be 100% Vested in the Earned Shares.

(b) Forfeiture. Except to the extent expressly provided in (i), (ii), (iii), or (iv) below, Holder permanently will forfeit all rights with respect to all Performance Shares upon the date of his Separation, if such Separation occurs prior to the Vesting Date.

(i)       Death. If Holder Separates by reason of death prior to the Vesting Date, Holder’s Beneficiary will be entitled to receive Performance Shares in an amount equal to the number of Target Performance Shares (and does not have any right to receive any other Performance Shares) as soon as reasonably possible, but in no event more than 90 days after Holder’s death.

(ii)       Disability. If Holder Separates by reason of a Disability prior to the Vesting Date, Holder will be entitled to receive Performance Shares in an amount equal to the number of Target Performance Shares (and does not have any right to receive any additional Performance Shares) as soon as reasonably possible, but in no event later than the 15th day of the third month after the end of the calendar year following the Date on which the Committee determines that Holder is Disabled.

(iii)       Post Separation Change in Control. If there is a Post Separation Change in Control, Holder will be entitled to receive Performance Shares in an amount equal to the number of Target Performance Shares (and does not have any right to receive any additional Performance Shares) as soon as reasonably possible after the date of the Change in Control, but in no event later than the 15th day of the third month after the end of the calendar year in which such Change in Control occurs.

(iv)       Retirement. If Holder Separates after reaching Holder’s Retirement Vesting Date and prior to the Vesting Date, Holder will be entitled to receive only that percentage (if any) of the Performance Shares as shall be determined by the Committee in writing (and does not have any right to receive any additional Performance Shares). In making its determination, the Committee will take into account the percentage of the Performance Period completed by the date of Holder’s Separation, and its best estimate of the Performance Percentage Points Holder has earned by the date of Holder’s Separation and is expected to earn during the portion of the Performance Period occurring after the date of Holder’s Separation. The Committee will make its determination, and Holder will receive the Performance Shares (if any) as determined by the Committee, within a reasonable time, but in no event later than the 15th day of the third month after the end of the calendar year following Holder’s Separation.  Notwithstanding the foregoing, in the event Holder Separates after Holder’s Retirement Vesting Date, but within 12 months of the Date of Grant, all rights to receive Performance Shares under this Award will be forfeited.

10.      Withholding. On the Vesting Date, the minimum federal income tax withholding required to be made by the Company shall be paid by Holder (or Holder’s Beneficiary) to the Administrator in cash, by delivery of Shares, or by authorizing the Company to retain Earned Shares, or a combination thereof; provided, further, that where Shares or Earned Shares are delivered or retained, the satisfaction of Holder’s obligation hereunder will be based on the Fair Market Value on the Vesting Date of such delivered or retained Shares.

11.      Issuance of Shares. Without limitation, Holder shall not have any of the rights and privileges of an owner of any of the Performance Shares (including voting rights) until the Vesting Date. The Administrator shall deliver the Vested Shares (reduced by the number of Vested Shares delivered to the Administrator to pay required withholding under section 10 above) to the Holder as soon as reasonably possible following vesting. The Holder agrees to hold and retain the required number of Vested Shares as specified in the Company’s stock ownership guidelines, as potentially modified from time to time.

12.      Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which Performance Measures have been satisfied and the number of Performance Percentage Points earned, exercise its right to reduce Performance Percentage Points, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties.

13.      Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Administrator a written designation of beneficiary (such person(s) being his “Beneficiary”), on such form as may be prescribed by the Administrator. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.

14.      Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Fiscal Year, the Committee (and the Administrator to the extent it shall have been directed by the Committee) shall make all relevant annually-determined calculations and determinations hereunder, and shall communicate such information to the Administrator. The Administrator will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.

15.      No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Earned Shares.

16.      No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right to continue to serve in the employ of the Company nor interfere in any way with Holder’s right to resign.

17.      Governing Law. Without limitation, this Award shall be construed and enforced in accordance with and governed by the laws of Delaware.

18.      Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto.

19.      Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.

20.      Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.

IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representative and Holder has hereunto set his or her hand, all on the day and year first above written.

Dated as of this 6th day of January, 2012.

DENBURY RESOURCES INC.

By:
	Phil Rykhoek CEO	Mark C. Allen Senior VP, CFO & Asst. Secretary

ACKNOWLEDGMENT

The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan.

Without limitation, I agree to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee upon any questions arising under the Plan, or this Award, or both.

Dated as of this  day of , 2012.

Officer Name

EX-10.B

Exhibit 10(b)

 $  Maximum Performance Cash

Date of Grant: January 6, 2012

2012 PERFORMANCE CASH AWARD

2004 OMNIBUS STOCK AND INCENTIVE PLAN

FOR DENBURY RESOURCES INC.

PERFORMANCE CASH AWARD (“Award”) made effective January 6, 2012 (“Date of Grant”) between Denbury Resources Inc. (the “Company”) and «Officer_Name» (“Holder”).

WHEREAS, Section 17 of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (“Plan”) authorizes the Committee to grant performance-based Awards;

WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn a maximum of $__________ based on the performance factors set forth in this Award, and subject to all of the provisions, including without limitation the Vesting provisions, of the Plan and this Award; and

WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award.

NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:

1.Performance Share Grant.  The Company hereby grants Holder the right to earn, Vest in and be paid on the Payment Date, up to $________ (“Performance Cash”) subject to the terms and conditions set forth in the Plan and in this Award.

2.Definitions.  All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:

(a)“BOE” means Barrels of Oil Equivalent, and for all purposes hereof, will be calculated using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

(b)“Committee Percentage Point Reduction” means the number (if any) of Performance Percentage Points (not in excess of the Committee Percentage Point Reduction Limitation) by which the Committee reduces Holder’s Performance Percentage Points in accordance with Section 7 hereof.

(c)“Committee Percentage Point Reduction Limitation” means the lesser of (i) forty (40) Performance Percentage Points, and (ii) the product of (x) Holder’s Performance Percentage Points earned during the Performance Period as determined prior to the application of the Committee Percentage Point Reduction, multiplied by (y) twenty-five percent (25%).

(d) “Disability” means, without limitation, the same as it does in the Plan.

(e)“Earned Performance Cash” means the amount of Performance Cash earned during the Performance Period as described and calculated in Section 8.

(f)“Fiscal Year” means the 12 month period adopted by the Company for financial reporting purposes.

(g)“Payment Date” means the date on which Performance Cash Vested and earned under this Award is paid to Holder, which shall be any date selected by the Committee which is not later than 30 days after the Vesting Date or such later date as may be caused by unusual circumstances beyond the reasonable control of the Committee.

(h)“Performance Measure” means, collectively, changes in amounts of oil and gas reserves, changes in production rates, and operating cost reductions, as determined based upon the (i) the Tertiary Oil Production Measure, (ii) the Corporate Production Measure, (iii) LOE per BOE Measure, and (iv) the Reserve Replacement Measure; provided, further, that when reference to a specific Performance Measure is intended, reference will be made to such specific Performance Measure.

(i) “Performance Period” means the period beginning on January 1, 2012, and ending on December 31, 2012.

(j)“Performance Percentage” means the excess of (i) Holder’s aggregate Performance Percentage Points, over (ii) the Committee Percentage Points Reduction, if any, determined as of the last day of the Performance Period.

(k)“Performance Percentage Points” means, collectively, the points, designated as Performance Percentage Points, earned with respect to each Performance Measure during Performance Period.

(l)“Performance Cash” means the amount of cash subject to this Award, as shown on the first page of this Award.

(m)“Post Separation Change in Control” means a Change in Control which follows Holder’s Separation, but results from the Commencement of a Change in Control that occurs prior to Holder’s Separation.  For all purposes of this Award, the term “Commencement of a Change in Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates.

(n)“Target Performance Cash” means $_______ of Performance Cash, which is the amount of Performance Cash which will be Earned if Holder’s Performance Percentage is 100%.

(o)“Vesting Date” means March 31, 2013.

3.Performance Percentage Points Earned With Respect To The Tertiary Oil Production Measure.

(a) Tertiary Production Based Performance Percentage Points. The Performance Percentage Points which will be credited to Holder with respect to the Tertiary Oil Production Measure are set forth in the following Chart based on the Average Annual Tertiary Production Percentage.  The “Average Annual Tertiary Production Percentage”means the quotient (rounded to 3 decimal places and then expressed as a percentage) of (x) the Adjusted Tertiary Oil Production for such Fiscal Year, divided by (y) the Tertiary Oil Production Forecast for such Fiscal Year.

	Average Annual Tertiary Production Percentage	Performance Percentage Points
A.	107.2% or more	70
B.	104.3% to 107.1%	56
C.	100% to 104.2%	42
D.	95.7% to 99.9%	28
E.	Less than 95.7%	0

(b)Adjusted Tertiary Oil Production.  For purposes of this Award, the “Adjusted Tertiary Oil Production” shall be equal to (i) the actual tertiary oil production of the Company for such Fiscal Year as reported in the Company’s Form 10-K, or if not specifically reported, then as determined by the Committee from the underlying documents, minus (ii) the tertiary oil production related to an oil property acquired during such Fiscal Year, such amount to be the lesser of (a) the actual tertiary oil production for such Fiscal Year from the acquired property or incremental property interest (if a material partial interest) or (b) the forecasted oil production related thereto for such Fiscal Year for the property before any improvements made by the Company following the acquisition of the property, plus (iii) that portion of the Tertiary Oil Production Forecast, as defined below which is related to any oil property disposed or sold during such Fiscal Year for the period during which the Company did not own the oil property.

(c)Tertiary Oil Production Forecast.  For purposes of this Award, for 2012 “Tertiary Oil Production Forecast” means 34,500 barrels of oil per day.

4.Performance Percentage Points Earned With Respect To The Corporate Production Measure.

(a)Corporate Production Based Performance Percentage Points.  The Performance Percentage Points which will be credited to Holder with respect to the Corporate Production Measure are set forth in the following Chart based on the Average Annual Corporate Production Percentage.  The “Average Annual Corporate Production Percentage” means for such Fiscal Year, the quotient (rounded to 3 decimal places and then expressed as a percentage) of (x) the Adjusted Corporate Production of the Company for such Fiscal Year, divided by (y) the Corporate Production Forecast for such Fiscal Year.

	Average Annual Corporate Production Percentage	Performance Percentage Points
A.	106.2% or more	40
B.	103.4% to 106.1%	32
C.	100% to 103.3%	24
D.	96.6% to 99.9%	16
E.	Less than 96.6%	0

(b)Adjusted Corporate Production.  For purposes of this Award, “Adjusted Corporate Production” means (i) the actual production of oil and natural gas (in BOEs) for the Fiscal Year as reported in the Company’s Form 10-K (“Corporate Production”), minus (ii) the oil and natural gas production (in BOEs) related to properties acquired during such Fiscal Year, such amount to be the lesser of (a) the actual oil and natural gas production (in BOEs) for such Fiscal Year from the acquired property or incremental property interest (if a partial interest) or (b) the forecasted oil and natural gas production (in BOEs) related thereto for such Fiscal Year for the property before any improvements made by the Company following the acquisition of the property, plus (iii) that portion of the Corporate Production Forecast, as defined below, which is related to any oil or natural gas property disposed or sold during such Fiscal Year for the period during which the Company did not own the property.

(c)Corporate Production Forecast.  For purposes of this Award, for 2012 “Corporate Production Forecast” means 72,750 BOE per day.

5.Performance Percentage Points Earned With Respect To Lease Operating Expense (“LOE”) Per BOE Measure.

(a)“Actual-to-Budget” LOE Per BOE Measure Performance Percentage Points.  The Performance Percentage Points which will be credited to Holder with respect to “Actual-to-Budget” LOE Per BOE Measure are set forth in the following Chart as compared to the various budgeted levels of LOE per BOE set forth in such Chart.

(b)“Actual LOE Per BOE” for such Fiscal Year means (x) the actual LOE for the Fiscal Year as reported in the Company’s Form 10-K for 2012 (less the cost for CO2 as per the Company’s detailed LOE analysis) minus total LOE (including cost for CO2) related to properties acquired during such Fiscal Year, plus for properties sold during such Fiscal Year, the originally budgeted LOE for that portion of such Fiscal Year during which the results of operations of such properties are not included in the Company’s financial results, divided by (y) the actual oil and natural gas production (in BOEs) for such Fiscal Year as reported in the Company’s Form 10-K for 2012, minus the actual oil and natural gas production (in BOEs) for such Fiscal Year from properties or incremental property interests (if a partial interest) acquired during such Fiscal Year, plus for properties sold during such Fiscal Year, the originally budgeted production for that portion of such Fiscal Year during which the results of operations of such properties are not included in the Company’s financial results.

(c)Performance Percentage Points.  The Performance Percentage Points which will be awarded Holder for the Performance Period with respect to the LOE per BOE Measure will be calculated as of the last day of the Performance Period, and will be based on the levels of Actual LOE per BOE during the Fiscal Year as compared to the levels shown in the following Chart:

	Actual LOE Per BOE	Performance Percentage Points
A.	Less than $17.68	50
B.	$17.68 to $18.15	40
C.	$18.16 to $18.78	30
D.	$18.79 to $19.45	20
E.	Greater than $19.45	0

6.Performance Percentage Points Earned With Respect To The Reserve Replacement Measure.

The Performance Percentage Points Holder will earn with respect to the Reserve Replacement Measure will be based on the Company’s Reserve Replacement Percentage for the entire Performance Period.  “Reserve Replacement Percentage“ means the quotient (rounded up to 3 decimal places and then expressed as a percentage) of (i) the Final Reserves less the Initial Reserves, divided by (ii) Total Production for the Company.

(a)Performance Percentage Points. The Performance Percentage Points which will be awarded Holder for the Performance Period with respect to the Reserve Replacement Measure are set forth in the following Chart:

	Reserve Replacement Percentage	Performance Percentage Points
A.	300% or more	40
B.	200% to 299%	32
C.	150% to 199%	24
D.	100% to 149%	16
E.	Less than 100%	0

(b)Initial Reserves.  For purpose of this Award, “Initial Reserves” means the total Company proved reserve quantities as of December 31, 2010 expressed in BOEs as estimated by DeGolyer and MacNaughton, independent petroleum engineers and disclosed in the Company’s Form 10-K Report for 2011.  

(c)Final Reserves.  For purposes of this Award, “Final Reserves” means the sum of (i) the total Company proved reserve quantities on the last day of the Performance Period expressed in BOEs as estimated by DeGolyer and MacNaughton or the Company’s then current independent petroleum engineer, determined using the same price deck as was used by the Company in calculating the Initial Reserves, plus (ii) the Uneconomic Reserves, plus (iii) the Disposed Reserves, plus (iv) Total Production.  The “Uneconomic Reserves” are those proved undeveloped reserves expressed in BOEs which were included in the Initial Reserves, but are not considered proved undeveloped reserves on the last day of the Performance Period solelybecause the price deck used to price oil and natural gas products and/or the prices used to estimate the capital costs required to develop the proved undeveloped reserves as of the last day of the Performance Period have changed from those used in the Initial Reserve report such that the extraction of such otherwise proved reserves is uneconomic (i.e. Uneconomic Reserves cannot be reserves excluded from the Final Reserves because drilling activity during the period changed the status or evaluation of the undeveloped reserves, or because the Company no longer holds the acreage or interest, or because factors other than commodity prices or changes in the estimated capital costs have made the project uneconomic).  The “Disposed Reserves” are those proved reserves quantities expressed in BOEs which were sold during the Performance Period as reported as such in the Company’s Form 10-K SFAS 69 disclosures.

7.Committee’s Reduction of Performance Percentage Points.

Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by written notice to Holder prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage Points by applying a Committee Percentage Point Reduction.

(a)Performance Percentage Points Reduction. The Committee will make its determination of the Committee Percentage Point Reduction amount (if any) based on the Committee’s subjective evaluation of Company performance with respect to each of the four Additional Committee Evaluation Factors listed in (b) below, which evaluation will determine the amount of the Performance Percentage Points reduction for each such Additional Committee Evaluation Factor based on the Chart below, and the sum of those reductions, but not in excess of the Committee Percentage Point Reduction Limitation, will be Committee Percentage Point Reduction for the Performance Period:

	Committee’s Determination of the Level of Performance With Respect to each Committee Evaluation Factor	Reduction in Performance Percentage Points
A.	Above Average	0
B.	Average	5
C.	Below Average	10

(b)For purposes of this Award, the “Additional Committee Evaluation Factors” (each of which may cause a reduction of up to 10 Performance Percentage Points) are:

(i)the Company’s compliance with such corporate governance factors as the ability to obtain an unqualified auditors’ opinion on the Company’s financial statements contained in its Form 10-K for 2012, and avoid any financial restatements,

(ii)the Company’s maintenance of a reasonable debt-to-capital and/or debt-to-cash flow ratio,

(iii)the Company’s record as to health, safety and environmental compliance and results, and

(iv)the increase in the net asset value per share of Company stock, determined after excluding the effects, to the extent reasonably practical, caused by fluctuations in commodity prices and capital and operating costs or other factors which are generally not controllable by the Company.

8.Earning  Performance Cash.

(a)Earned Performance Cash.  The amount of Earned Performance Cash shall be equal to the product of (i) the Target Performance Cash, multiplied by (ii) the Performance Percentage.  The Committee will determine, and the Administrator will advise Holder, of Holder’s Performance Percentage as soon as reasonably possible after the last day of the Performance Period.

(b)Change in Control.  Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change in Control occurs during the Performance Period then, regardless of the Performance Percentage at the date of the Change in Control, Holder will be entitled to receive delivery of all of the Target Performance Cash (notwithstanding any provision hereof to the contrary, none of which Target Performance Cash will be retained by the Company other than as payment for withholding) as soon as reasonably possible following such Change in Control, but in no event later than the 15th day of the third month after the end of the calendar year in which such Change in Control occurs, and Holder permanently shall forfeit the right to receive any other amounts of Performance Cash.

9.Vesting (and Forfeiture) of Earned Performance Cash.

(a)No Separation Prior to the Vesting Date.  If Holder does not Separate prior to the Vesting Date, Holder will be 100% Vested in the Earned Cash.

(b)Forfeiture. Except to the extent expressly provided in (i), (ii), (iii), or (iv) below, Holder permanently will forfeit all rights with respect to any Performance Cash upon the date of his Separation, if such Separation occurs prior to the Vesting Date.

(i)Death.  If Holder Separates by reason of death prior to the Vesting Date, Holder’s Beneficiary will be entitled to receive Performance Cash in an amount equal to the Target Performance Cash (and does not have any right to receive any other amounts of Performance Cash) as soon as reasonably possible but in no event more than 90 days after Holder’s death.

(ii)Disability.  If Holder Separates by reason of a Disability prior to the Vesting Date, Holder will be entitled to receive Performance Cash in an amount equal to the Target Performance Cash (and does not have any right to receive any additional amounts of Performance Cash) as soon as reasonably possible but in no event later than the 15th day of the third month after the end of the calendar year following the Date on which the Committee determines that Holder is Disabled.

(iii)Post Separation Change in Control.  If there is a Post Separation Change in Control, Holder will be entitled to receive Performance Cash in an amount equal to the Target Performance Cash (and does not have any right to receive any additional Performance Cash) as soon as reasonably possible after the date of the Change in Control but in no event later than the 15th day of the third month after the end of the calendar year in which such Change in Control occurs.

(iv)Retirement.  If Holder Separates after reaching Holder’s Retirement Vesting Date and prior to the Vesting Date, Holder will be entitled to receive only that  percentage (if any) of the Performance Cash as shall be determined by the Committee in writing (and does not have any right to receive any additional amounts of Performance Cash).  In making its determination, the Committee will take into account the percentage of the Performance Period completed by the date of Holder’s Separation, and its best estimate of the Performance Percentage Points Holder has earned by the date of Holder’s Separation and is expected to earn during the portion of the Performance Period occurring after the date of Holder’s Separation.  The Committee will make its determination, and Holder will receive the Performance Cash (if any) as determined by the Committee, within a reasonable time but in no event later than the 15th day of the third month after the end of the calendar year following  Holder’s Separation.  Notwithstanding the foregoing, in the event Holder Separates after Holder’s Retirement Vesting Date, but within 12 months of the Date of Grant, all rights to receive Performance Cash under this Award will be forfeited.

10.Withholding.  On the Vesting Date, the minimum federal income tax withholding required to be made by the Company shall be paid by Holder (or Holder’s Beneficiary) to the Administrator in cash, or by authorizing the Company to retain an amount of Performance Cash.

11.Administration.  Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award.  Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which Performance Measures have been satisfied and the number of Performance Percentage Points earned, exercise its right to reduce Performance Percentage Points, and make all other determinations and take all other actions necessary or desirable for the administration of the Award.  The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award.  All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties.

12.Beneficiary.  Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative.  Holder may file with the Administrator a written designation of beneficiary (such person(s) being his “Beneficiary”), on such form as may be prescribed by the Administrator. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.

13.Holder’s Access to Information.  As soon as reasonably possible after the close of the preceding Fiscal Year, the Committee (and the Administrator to the extent it shall have been directed by the Committee) shall make all relevant annually-determined calculations and determinations hereunder, and shall communicate such information to the Administrator.  The Administrator will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.

14.No Transfers Permitted.  The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Earned Shares.

15.No Right To Continued Employment.Neither the Plan nor this Award shall confer upon Holder any right to continue to serve in the employ of the Company nor interfere in any way with Holder’s right to resign.

16.Governing Law.  Without limitation, this Award shall be construed and enforced in accordance with and governed by the laws of Delaware.

17.Binding Effect.  This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto.

18.Waivers.  Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right.  Any such waiver shall not be deemed to be a waiver of any other rights.

19.Severability.  If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.

IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representative and Holder has hereunto set his or her hand, all on the day and year first above written.

Dated as of this 6th day of January, 2012.

DENBURY RESOURCES INC.

By:
	Phil Rykhoek CEO	Mark C. Allen Senior VP, CFO & Asst. Secretary

ACKNOWLEDGMENT

The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan.

Without limitation, I agree to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee upon any questions arising under the Plan, or this Award, or both.

Dated as of this  day of , 2012.

Officer Name

EX-10.C

Exhibit 10(c)

Maximum Performance Shares

Date of Grant: March 8, 2012

2012 TSR PERFORMANCE AWARD

2004 OMNIBUS STOCK AND INCENTIVE PLAN

DENBURY RESOURCES INC.

This TSR PERFORMANCE AWARD (“Award”) made effective March 8, 2012 (“Date of Grant”) between Denbury Resources Inc. (the “Company”) and «Officer_Name»(“Holder”).

WHEREAS, Section 17 of the 2004 Omnibus Stock and Incentive Plan For Denbury Resources Inc. (“Plan”) authorizes the Committee to grant performance-based Awards;

WHEREAS, the Committee desires to grant to Holder an Award under which Holder can earn a maximum of  Performance Shares based on the performance factors set forth in this Award, and subject to all of the provisions, including without limitation the Vesting provisions, of the Plan and this Award;

WHEREAS, no Performance Shares will be issued or outstanding until their respective Vesting Dates; and

WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award, and all capitalized terms used but not defined herein shall have the meaning given to those terms in the Plan.

NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:

1.   Performance Share Grant. The Company hereby grants Holder the right to earn, Vest in, and receive delivery of on the Delivery Date, up to  Reserved Shares (“Performance Shares”) subject to the terms and conditions set forth in the Plan and in this Award.

2.   Definitions. All words capitalized herein that are defined in the Plan shall have the meaning assigned them in the Plan; other capitalized words shall have the following meaning, or shall be defined elsewhere in this Award:

(a)   “Annual TSR” means for the Company and each Peer Company, the result, expressed as a percentage, of the calculation of TSR for each of them set out in Section 4(a) hereof as to a Calendar Year within the Performance Period.

(b)   “Beginning Common Stock Price” means the average of the Closing Price of the primary common equity security for the Company and each Peer Company for each of the 10 trading days immediately preceding the first day of each Calendar Year, taken separately, within the Performance Period being measured.

(c)   “Calendar Year” means the 12-month period beginning January 1 and ending December 31 for the Company and each Peer Company.

(d)   “Change in Control” or “CIC” means the same as it does in the Plan.

(e)   “Closing Price” means the last reported sales price, regular way, of the primary common equity security of the Company and each Peer Company, as reported by the primary exchange or the market upon which such security is traded.

(f)   “Delivery Date” means the date on which Vested Earned Shares are delivered to Holder, which shall be the Vesting Date, or as soon thereafter as practicable, but in no event later than 30 days after the Vesting Date.

(g)   “Disability” means, without limitation, the same as it does in the Plan.

(h)   “Earned Performance Shares” means the number of Performance Shares which are earned during the Performance Period as described and calculated in Section 6.

(i)   “Ending Common Stock Price” equals the average of the Closing Price of the primary common equity security for the Company and each Peer Company for each of the 10 trading days ending on and including the last day of each Calendar Year, taken separately, within the Performance Period.

(j)   “Peer Company” means each of the companies listed on Appendix A hereto that has its primary common equity securities listed or traded on a United States national securities exchange, NASDAQ National Market, or Toronto Stock Exchange during each day of each Calendar Year, taken separately, within the Performance Period.

(k)   “Performance Period” means the period beginning on January 1, 2012, and ending on December 31, 2014, provided that in the event of a Change in Control, the Performance Period will end on the date that such Change in Control takes effect.

(l)   “Performance Percentage” means that percentage determined based upon the relative ranking of the Company’s Three-Year Average TSR for the Performance Period compared to the Three-Year Average TSR of each Peer Company for the Performance Period as determined under the provisions of Section 4(c), subject to reduction under Sections 5 and 12, if any.

(m)   “Post Separation Change in Control” means a Change in Control that follows Holder’s Separation, but results from the Commencement of a Change in Control that occurs prior to Holder’s Separation. For all purposes of this Award, the term “Commencement of a Change in Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates.

(n)   “Target Performance Shares” means one-half of the Performance Shares which may be earned under this Award if there are no reductions in the number of performance shares under Section 5.

(o)   “Three-Year Average TSR” means for the Company and each Peer Company, the result, expressed as a percentage, of averaging their respective Annual TSR for each of the 2012, 2013 and 2014 Calendar Years.

(p)   “Total Shareholder Return” or “TSR” shall mean that percentage which reflects the increase or decrease in the average closing trading price of the Company’s or a Peer Company’s primary common equity security (assuming reinvestment of any dividends) between the last 10 trading days of one Calendar Year and the last 10 trading days of the next Calendar Year, or as applicable, the average of such yearly increases or decreases.

(q)   “Value of Reinvested Dividends” means a dollar amount derived by (i) calculating an aggregate number of shares (or fractions thereof) of the Company or any Peer Company represented by the sum of each dividend paid on their respective primary common equity security during a Calendar Year (or portion thereof under Section 4(b) below) within the Performance Period, determined by dividing the per share amount or value paid through each such dividend by the Closing Price of that company’s primary common equity security on each such dividend payment date, and (ii) then multiplying that aggregate number of shares by the Ending Common Stock Price, respectively, of that company for that Calendar Year (or portion thereof in the event of a Change in Control).

(r)   “Vesting Date” means March 31, 2015 (or the effective date of any earlier Change in Control).

3.   Performance Shares as Contractual Right.  Each Performance Share represents a contractual right to receive one share of common stock of the Company, subject to the terms and conditions of this Award; provided that, based on relative Total Shareholder Return as detailed below, the number of shares of common stock of the Company that may be deliverable hereunder in respect of the Performance Shares may range from 0% to 200% of the number of Target Performance Shares, and Holder’s right to receive common stock of the Company in respect of Performance Shares is generally contingent.

4. Total Shareholder Return Calculations. Total Shareholder Return shall be calculated for the periods specified below as follows:

(a)   Annual TSR for the Company and each Peer Company for each Calendar Year within the Performance Period shall equal the result of the following calculation for each such company:

Ending Common Stock Price + Value of Reinvested Dividends	– 1
Beginning Common Stock Price

(b)   For any Calendar Year in which a Change in Control of the Company occurs, Annual TSR for the Company and each Peer Company for that Calendar Year shall equal the result of the following calculation for each such company:

(c)   The Three-Year Average TSR of the Company and each Peer Company is to be calculated as soon as practical after the end of the Performance Period.  A ranking is to be made of the Three-Year Average TSR for each Peer Company and the Company, and they are to be listed in Column 1 of the table below in descending order of their respective Three-Year Average TSR from the highest percentage to the lowest percentage, and reflecting in Column 2 the exact percentage of each company’s respective Three-Year Average TSR.

The Company’s Performance Percentage will be that percentage shown in Column 4 (subject to adjustment, if any, provided in Sections 5 or 12) opposite the ranking of the Company in Column 1 (for example, in the following table for 11 Peer Companies, being ranked as fifth would equal a Performance Percentage of 127%).

Three-Year Average TSR Rank of the Company and Peer Companies	Actual Three-Year Average TSR (expressed as a %)	Scale of Three-Year Average TSR for 11 Peer Companies (expressed as a %)	Performance Percentage Scale (subject to interpolation)
1	2	3	4
1		100.00%	200%
2		90.90%	182%
3		81.80%	164%
4		72.70%	145%
5		63.60%	127%
6		54.50%	109%
7		45.50%	91%
8		36.40%	73%
9		27.30%	55%
10		18.20%	36%
11		9.10%	18%
12		0.00%	0%

The percentages in Column 3 of the table above are based upon increments derived by dividing 100% by 11 Peer Companies, which percentage increments will be adjusted, if necessary, on a pro rata basis to reflect a reduction in the number of Peer Companies (i.e. if, for example, at the end of the Performance Period there were nine Peer Companies, then the 9.1% increments currently shown in Column 3 would each become 11.1% increments, and the percentages in Column 4 would be adjusted to twice the adjusted incremental percentages reflected in the same row of Column 3).

5.   Committee’s Reduction of Performance Percentage.  Notwithstanding any provision hereof to the contrary, the Committee, in its sole discretion, by written notice to Holder prior to the Vesting Date, may reduce Holder’s otherwise earned Performance Percentage in an amount (if any) based upon the Committee’s subjective evaluation.  Any reduction of Holder’s Performance Percentage by the Committee for the Performance Period shall be determined after the end of the Performance Period, and shall not exceed twenty-five percent (25%) of Holder’s Performance Percentage earned during the Performance Period.

6.   Earned Performance Shares.

(a) Earned Performance Shares. The number of Earned Performance Shares shall be equal to the product of (i) the Target Performance Shares, multiplied by (ii) the Performance Percentage, as such number shall be reduced by the Company to satisfy all minimum applicable federal, state, and local income tax withholding requirements and employment tax withholding requirements. Only whole shares will be issued to the Holder.  The Performance Percentage shall be determined by the Committee and the Holder will be advised as soon as administratively practicable following the end of the Performance Period (but in no case later than 90 days after the end of the Performance Period), and the Committee shall certify whether and to the extent that the Performance Percentage has been achieved, subject to the Change in Control provisions of Section 6(b) below.

(b) Change in Control. Notwithstanding the foregoing and any other provision hereof to the contrary, if a Change in Control occurs during the Performance Period then, regardless of the Performance Percentage at the date of the Change in Control, the Performance Period will end on the date of the Change in Control and the performance for the partial year will be annualized as set out in Section 4(b) above and averaged with the Annual TSR calculated for any prior completed Calendar Year to determine Earned Performance Shares, which Holder will be entitled to receive on the date of the Change in Control, but in no event later than the 15th day of the third month after the end of the calendar year in which such Change in Control occurs, and Holder permanently shall forfeit the right to receive any other Performance Shares.

7. Vesting (and Forfeiture) of Earned Performance Shares.

(a) No Separation Prior to the Vesting Date. If Holder does not Separate prior to the Vesting Date (other than a Separation after Holder’s Retirement Vesting Date), Holder will be 100% Vested in the Earned Performance Shares.

(b) Retirement Vesting Date.In the event Holder reaches his Retirement Vesting Date prior to the Vesting Date, Holder will be entitled to receive Performance Shares in an amount equal to the number of Earned Performance Shares on the Vesting Date (which shares will be delivered to the employee on the Delivery Date), without any right to receive any additional Performance Shares, and without any proration of the number of Performance Shares earned in such circumstances. Notwithstanding the foregoing, in the event Holder Separates after Holder’s Retirement Vesting Date, but within 12 months of the Date of Grant, all rights to receive Performance Shares under this Award will be forfeited.

(c) Forfeiture. Except to the extent expressly provided in (i), (ii) or (iii) below, Holder permanently will forfeit all rights with respect to all Performance Shares upon the date of his Separation, if such Separation occurs prior to the Vesting Date.

(i) Death. If Holder Separates by reason of death prior to the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive Performance Shares in an amount equal to the number of Target Performance Shares (without any right to receive any other Performance Shares) as soon as reasonably possible, but in no event more than 90 days after Holder’s death. If Holder Separates by reason of death prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the number of Performance Shares based on the calculation in Section 6 herein (and does not have any right to receive any other Performance Shares) as soon as reasonably possible, but in no event more than 90 days after Holder’s death.

(ii) Disability. If Holder Separates by reason of Disability prior to the last day of the Performance Period, Holder or Holder’s Beneficiary, as applicable, will be entitled to receive Performance Shares in an amount equal to the number of Target Performance Shares (without any right to receive any other Performance Shares) as soon as reasonably possible, but in no event later than the 15th day of the third month after the end of the calendar year following the Date on which the Committee determines that Holder is Disabled. If Holder Separates by reason of Disability prior to the Vesting Date but on or after the last day of the Performance Period, Holder’s Beneficiary will be entitled to receive the number of Performance Shares based on the calculation in Section 6 herein (without any right to receive any other Performance Shares) as soon as reasonably possible, but in no event later than the 15th day of the third month after the end of the calendar year following the Date on which the Committee determines that Holder is Disabled.

(iii) Post Separation Change in Control. If there is a Post Separation Change in Control, Holder will be entitled to receive Performance Shares in an amount equal to the number of Target Performance Shares (without any right to receive any additional Performance Shares) as soon as reasonably possible after the date of the Change in Control, but in no event later than the 15th day of the third month after the end of the calendar year in which such Change in Control occurs.

8.   Withholding. On the Vesting Date, the minimum statutory tax withholding required to be made by the Company shall be paid by Holder (or Holder’s Beneficiary) to the Administrator in cash, by delivery of Shares, or by authorizing the Company to retain Earned Performance Shares, or a combination thereof; provided, further, that where Shares or Earned Performance Shares are delivered or retained, the satisfaction of Holder’s obligation hereunder will be based on the Fair Market Value on the Vesting Date of such delivered or retained Shares.

9.  Issuance of Shares. Without limitation, Holder shall not have any of the rights and privileges of an owner of any of the Performance Shares (including voting rights) until the Vesting Date. The Administrator shall deliver the Vested Shares (reduced by the number of Vested Shares delivered to the Administrator to pay required withholding under Section 8 above) to the Holder as soon as reasonably possible following vesting. The Holder agrees to hold and retain the required number of Vested Shares as specified in the Company’s stock ownership guidelines, as potentially modified from time to time.

10.  Administration. Without limiting the generality of the Committee’s rights, duties and obligations under the Plan, the Committee shall have the following specific rights, duties and obligations with respect to this Award. Without limitation, the Committee shall interpret conclusively the provisions of the Award, adopt such rules and regulations for carrying out the Award as it may deem advisable, decide conclusively all questions of fact arising in the application of the Award, certify the extent to which Performance Measures have been satisfied and the Performance Percentage earned, exercise its right to reduce the Performance Percentage, and make all other determinations and take all other actions necessary or desirable for the administration of the Award. The Committee is authorized to change any of the terms or conditions of the Award in order to take into account any material unanticipated change in the Company’s operations, corporate structure, assets, or similar change, but only to the extent such action carries out the original purpose, intent and objectives of the Award. All decisions and acts of the Committee shall be final and binding upon Holder and all other affected parties.

11.  Beneficiary. Holder’s rights hereunder shall be exercisable during Holder’s lifetime only by Holder or Holder’s legal representative. Holder may file with the Administrator a written designation of beneficiary (such person(s) being his “Beneficiary”), on such form as may be prescribed by the Administrator. Holder may, from time to time, amend or revoke a designation of Beneficiary. If no designated Beneficiary survives Holder, the Holder’s estate shall be deemed to be Holder’s Beneficiary.

12. Adjustments in Respect of Performance Shares. In addition to any adjustments under Section 5 herein, in the event of any dividend or split of the primary common equity security of the Company or any Peer Company, or recapitalization (including, but not limited to, the payment of an extraordinary dividend), merger, consolidation, combination, spin-off, distribution of assets to stockholders (other than cash dividends), exchange of such shares, or other similar corporate change, with regard to the Company or any Peer Company, appropriate adjustments may be made to the number of Target Performance Shares in a manner deemed equitable by the Committee.

13.  Holder’s Access to Information. As soon as reasonably possible after the close of the preceding Calendar Year, the Committee (and the Administrator to the extent it shall have been directed by the Committee) shall make all relevant annually determined calculations and determinations hereunder, and shall communicate such information to the Administrator. The Administrator will furnish all such relevant information to Holder as soon as reasonably possible following the date on which all, or a substantial majority, of the information is available.

14. No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Earned Performance Shares.

15. No Right To Continued Employment. Neither the Plan nor this Award shall confer upon Holder any right to continue to serve in the employ of the Company nor interfere in any way with Holder’s right to resign.

16. Governing Law. Without limitation, this Award shall be construed and enforced in accordance with and governed by the laws of Delaware.

17. Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto.

18. Waivers. Any waiver of any right granted pursuant to this Award shall not be valid unless it is in writing and signed by the party waiving the right. Any such waiver shall not be deemed to be a waiver of any other rights.

19. Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.

IN WITNESS WHEREOF, the Company has caused this Award to be executed on its behalf by its duly authorized representative and Holder has hereunto set his or her hand, all on the day and year first above written.

Dated as of this 8th day of March, 2012.

DENBURY RESOURCES INC.

By:
	Phil Rykhoek Chief Executive Officer	Mark C. Allen Senior Vice President and Cheif Financial Officer

ACKNOWLEDGMENT

The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan.

Without limitation, I agree to accept as binding, conclusive and final all decisions, factual determinations, and/or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or Award, or both) of the Committee upon any questions arising under the Plan, or this Award, or both.

Dated as of this  day of , 2012.

Officer Name

Appendix A

Peer Companies

Berry Petroleum Company (BRY)

Concho Resources, Inc. (CXO)

Continental Resources, Inc. (CLR)

MEG Energy Corporation (MEG.TO)

Nexen, Inc. (NXY)

Oasis Petroleum, Inc. (OAS)

Pioneer Natural Resources Company (PXD)

Plains Exploration & Production Company (PXP)

Sandridge Energy, Inc. (SD)

SM Energy Company (SM)

Whiting Petroleum Corporation (WLL) 

In the event that any company within the Peer Group is acquired or ceases to have its primary common equity security listed or traded on a U.S. national securities exchange, the Toronto Stock Exchange, or the NASDAQ National Market (or any successors thereto) during the Performance Period, such company will be removed from the Peer Group for the purposes of calculating achievement of the Performance Percentage.

EX-31.A

Exhibit 31(a)

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.

May 10, 2012	/s/ Phil Rykhoek
	Phil Rykhoek
	Chief Executive Officer

EX-31.B

Exhibit 31(b)

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.

May 10, 2012	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

EX-32

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 March 31, 2012 (the “Report”) of Denbury Resources Inc. (“Denbury”) as filed with the Securities and Exchange Commission on May 10, 2012, 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: May 10, 2012	/s/ Phil Rykhoek
	Phil Rykhoek
	Chief Executive Officer
Dated: May 10, 2012	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

XML

Fair Value Measurements (Quantitative Information About Level 3 Instruments) (USD $)	3 Months Ended
	Mar. 31, 2012
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Derivative Assets (Liabilities), at Fair Value, Net	$ (37,965,000)
Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Derivative Assets (Liabilities), at Fair Value, Net	22,310,000
Significant Unobservable Inputs (Level 3) [Member] | Income Approach Valuation Technique [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Derivative Assets (Liabilities), at Fair Value, Net	$ 22,310,000
Fair Value Measurements Valuation Techniques	Discounted Cash Flow
Tetco M1 [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Derivative Settlement Period Date Range Start	2012-04-01
Derivative Settlement Period Date Range End	2012-12-31
Tetco M1 [Member] | Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Pricing Index	TETCO M1
Tetco M1 [Member] | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Forward Pricing Range	3.21
Tetco M1 [Member] | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Forward Pricing Range	2.09
Houston Ship Channel [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Derivative Settlement Period Date Range Start	2012-04-01
Derivative Settlement Period Date Range End	2012-12-31
Houston Ship Channel [Member] | Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Pricing Index	Houston Ship Channel
Houston Ship Channel [Member] | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Forward Pricing Range	3.09
Houston Ship Channel [Member] | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Forward Pricing Range	2.06
Natural Gas Midcontinent [Member]
Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Derivative Settlement Period Date Range Start	2012-04-01
Derivative Settlement Period Date Range End	2012-12-31
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Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Pricing Index	Natural Gas – Midcontinent
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Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Forward Pricing Range	3.05
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Quantitative valuation techniques for assets and liabilities measured on a nonrecurring basis (Level 3)
Forward Pricing Range	1.98

XML

Acquisitions and Divestitures (Details Textuals) (USD $)	3 Months Ended		0 Months Ended	1 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Jan. 10, 2012 Petro Harvester [Member] Petro Harvester Gulf Coast Holdings LLC [Member]	Feb. 29, 2012 Petro Harvester [Member] Petro Harvester Gulf Coast Holdings LLC [Member]	Aug. 31, 2011 Riley Ridge Phase 2 [Member]
Acquisitions and Divestitures (Textuals) [Abstract]
Working interest in business acquisition					57.50%
Ownership Interest					57.50%
Net proceeds from sales of oil and natural gas properties and equipment	$ 166,703,000	$ 11,989,000		$ 144,800,000
Deferred Riley Ridge acquisition consideration					15,000,000
Anticipated Proceeds From Sale Of Oil And Natural Gas Properties			155,000,000
Business Acquisition, Cost of Acquired Entity, Purchase Price					$ 214,800,000
Effective Date Of Transaction	Dec. 01, 2011

XML

Basis of Presentation

3 Months Ended

Mar. 31, 2012

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company. We are the largest combined 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 our 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, 2011. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2012,ourconsolidated results of operations for thethree months ended March 31, 2012 and 2011, and our consolidated cash flows for the three months ended March 31, 2012 and 2011. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. On the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011, “Taxes other than income”is a new line item and includes oil and natural gas ad valorem taxes, which were reclassified from “Lease operating expenses,”franchise taxes and property taxes on buildings, which were reclassified from “General and administrative,” oil and natural gas production taxes, which were reclassified from “Production taxes and marketing expenses” used in prior reports and CO2 property ad valorem and production taxes, which were classified from “CO2 discovery and operating expenses.” Such reclassifications had no impact on our reported total expenses or net income.

Restricted Cash

Restricted cash consists of proceeds from the sale of oil and gas properties in February 2012 that are held by aqualified intermediary and are restricted for the pending acquisition of Thompson Field (see Note 8, Subsequent Events) to facilitate an anticipatedlike-kind exchange transaction.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to common 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 to net income and common shares of the potential dilution from stock options, stock appreciation rights (“SARs”), nonvested restricted stock, and nonvested performance equity awards. For thethree months ended March 31, 2012 and 2011, there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:

		Three Months Ended
		March 31,
In thousands		2012	2011
Basic weighted average common shares		386,367	397,386
Potentially dilutive securities:
	Stock options and SARs	3,330	—
	Performance equity awards	117	—
	Restricted stock	1,129	—
Diluted weighted average common shares		390,943	397,386

Basic weighted average common shares excludes 3.9million and 3.7million sharesof nonvested restricted stockduring the three months ended March 31, 2012 and 2011, respectively. 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, the nonvested 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 antidilutive:

		Three Months Ended
		March 31,
In thousands		2012	2011
Stock options and SARs		3,179	12,641
Restricted stock		10	3,453
	Total	3,189	16,094

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 December 31, 2011, 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 Encore Energy Partners LP to a subsidiary of Vanguard on December 31, 2010. We received distributions of $1.8millionon the Vanguard common units we owned for the three months ended March 31, 2011, which are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. During January 2012, the Company sold its investment in Vanguard for cash consideration of $83.5million, net of related transaction fees. The Company recognized a pretax loss on the sale of $3.1million, which is included in “Other expenses” on our Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012.

Recently Adopted Accounting Pronouncements

Comprehensive Income.In June 2011, the Financial Accounting Standards Board (“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 was effective for Denbury beginning January 1, 2012. Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends the Financial Accounting Standards Board Codification (“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 was effective for Denbury beginning January 1, 2012. The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures. See Note 5, Fair Value Measurements.

XML

Derivative Instruments and Hedging Activities (Oil and Natural Gas Commodity Derivatives Outstanding)	Mar. 31, 2012
Year 2012 [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	54,250
Year 2012 [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	54,250
Year 2012 [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	54,250
Year 2012 [Member] | Natural Gas Contracts [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	20,000
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] | Q2 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	137.50
Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q2 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	70.00
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
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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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
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Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q4 [Member] | Maximum [Member]
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Year 2012 [Member] | Collars [Member] | Oil contracts [Member] | Q4 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Floor price	0
Ceiling price	0
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Year 2012 [Member] | Collars [Member] | Natural Gas Contracts [Member] | Maximum [Member]
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Ceiling price	0
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Year 2012 [Member] | Swap [Member] | Oil contracts [Member] | Q2 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
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Year 2012 [Member] | Swap [Member] | Oil contracts [Member] | Q2 [Member] | Minimum [Member]
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Ceiling price	0
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Floor price	65.00
Ceiling price	0
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Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	65.00
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Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	65.00
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Floor price	65.00
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Year 2012 [Member] | Put [Member] | Oil contracts [Member] | Q3 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	65.00
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Floor price	65.00
Ceiling price	0
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Commodity Derivative Contracts Not Classified as Hedging Instruments
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Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	65.00
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Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
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Year 2012 [Member] | Put [Member] | Natural Gas Contracts [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2012 [Member] | Put [Member] | Natural Gas Contracts [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	55,000
Year 2013 [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	50,000
Year 2013 [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	50,000
Year 2013 [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Volume per Day	18,000
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	70.00
Ceiling price	110.32
Volume per Day	55,000
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q1 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	117.00
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q1 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	70.00
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	75.00
Ceiling price	116.92
Volume per Day	50,000
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q2 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	124.20
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q2 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	75.00
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	75.00
Ceiling price	122.14
Volume per Day	50,000
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q3 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	133.10
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q3 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	75.00
Year 2013 [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	126.63
Volume per Day	18,000
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q4 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	127.50
Year 2013 [Member] | Collars [Member] | Oil contracts [Member] | Q4 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	80.00
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q1 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q1 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q2 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q2 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q3 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q3 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q4 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Swap [Member] | Oil contracts [Member] | Q4 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q1 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q1 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q1 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q2 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q2 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q2 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q3 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q3 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q3 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q4 [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Swap price	0
Floor price	0
Ceiling price	0
Volume per Day	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q4 [Member] | Maximum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0
Year 2013 [Member] | Put [Member] | Oil contracts [Member] | Q4 [Member] | Minimum [Member]
Commodity Derivative Contracts Not Classified as Hedging Instruments
Derivative Price Range	0

XML

Derivative Instruments and Hedging Activities (Summary of Derivative Income/Expense) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives expense	$ 45,275,000	$ 170,750,000
Oil contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Payment (receipt) on settlements of derivative contracts	8,230,000	5,028,000
Fair value adjustments to derivative contracts - expense (income)	42,445,000	167,064,000
Total derivatives expense (income) - oil & natural gas	50,675,000	172,092,000
Natural Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Payment (receipt) on settlements of derivative contracts	(7,040,000)	(6,616,000)
Fair value adjustments to derivative contracts - expense (income)	1,640,000	5,274,000
Total derivatives expense (income) - oil & natural gas	$ (5,400,000)	$ (1,342,000)

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Derivative Instruments and Hedging Activities (Derivatives By Balance Sheet Location) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Derivative financial instruments in Balance Sheet
Derivative Assets, Current	$ 23,015,000	$ 47,402,000
Derivative Assets, Noncurrent	1,245,000	29,000
Derivative Liabilities, Current	41,972,000	26,523,000
Derivative Liabilities, Noncurrent	22,013,000	18,872,000
Not Designated as Hedging Instrument [Member]
Derivative financial instruments in Balance Sheet
Derivative, Fair Value, Net	(39,725,000)	2,036,000
Oil contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative financial instruments in Balance Sheet
Derivative Assets, Current	705,000	23,452,000
Derivative Assets, Noncurrent	1,245,000	29,000
Derivative Liabilities, Current	(40,212,000)	(22,610,000)
Derivative Liabilities, Noncurrent	(22,013,000)	(18,702,000)
Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative financial instruments in Balance Sheet
Derivative Assets, Current	22,310,000	23,950,000
Deferred Premiums [Member] | Not Designated as Hedging Instrument [Member]
Derivative financial instruments in Balance Sheet
Derivative Liabilities, Current	(1,760,000)	(3,913,000)
Derivative Liabilities, Noncurrent	$ 0	$ (170,000)

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Fair Value Measurements (Fair Value Heirarchy Table) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments		$ 86,682,000
Oil and natural gas derivative contracts	24,260,000	47,431,000
Oil and natural gas derivative contracts	(62,225,000)	(41,312,000)
Total		92,801,000
Total	(37,965,000)
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments		86,682,000
Oil and natural gas derivative contracts	0	0
Oil and natural gas derivative contracts	0	0
Total		86,682,000
Total	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments		0
Oil and natural gas derivative contracts	1,950,000	23,481,000
Oil and natural gas derivative contracts	(62,225,000)	(41,312,000)
Total		(17,831,000)
Total	(60,275,000)
Significant Unobservable Inputs (Level 3) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Short-term investments		0
Oil and natural gas derivative contracts	22,310,000	23,950,000
Oil and natural gas derivative contracts	0	0
Total		23,950,000
Total	$ 22,310,000

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash flows from operating activities
Net income (loss)	$ 113,467,000	$ (14,190,000)
Adjustments needed to reconcile to net cash flow provided by operations
Depletion, depreciation, and amortization	120,895,000	93,594,000
Deferred income taxes	37,137,000	(7,908,000)
Stock-based compensation	7,913,000	10,201,000
Noncash fair value derivative adjustments	44,113,000	172,367,000
Loss on early extinguishment of debt	0	15,783,000
Amortization of debt issuance costs and discounts	3,674,000	5,051,000
Impairment of assets	17,300,000	0
Other, net	7,725,000	(3,681,000)
Changes in operating assets and liabilities:
Accrued production receivable	(8,863,000)	(44,243,000)
Trade and other receivables	9,162,000	(17,484,000)
Other current and long-term assets	676,000	(8,449,000)
Accounts payable and accrued liabilities	(32,861,000)	(90,382,000)
Oil and natural gas production payable	(470,000)	18,770,000
Other liabilities	(28,214,000)	(4,597,000)
Net cash provided by operating activities	291,654,000	124,832,000
Cash flows from investing activities
Oil and natural gas capital expenditures	(302,246,000)	(190,296,000)
Acquisitions of oil and natural gas properties	(592,000)	(29,801,000)
CO2 capital expenditures	(30,693,000)	(27,150,000)
Pipelines and plants capital expenditures	(60,441,000)	(38,897,000)
Purchases of other assets	(4,945,000)	(12,770,000)
Net proceeds from sales of oil and natural gas properties and equipment	166,703,000	11,989,000
Addition to restricted cash	(140,131,000)	0
Proceeds from sale of short-term investments	83,545,000	0
Other	(83,000)	1,882,000
Net cash used for investing activities	(288,883,000)	(285,043,000)
Cash flows from financing activities
Bank repayments	(150,000,000)	(130,000,000)
Bank borrowings	210,000,000	130,000,000
Repayment of senior subordinated notes	0	(469,552,000)
Premium paid on repayment of senior subordinated notes	0	(13,137,000)
Net proceeds from issuance of senior subordinated notes	0	400,000,000
Net proceeds from issuance of common stock	3,949,000	5,253,000
Costs of debt financing	(11,000)	(8,441,000)
Other	(8,036,000)	(7,924,000)
Net cash provided by (used for) financing activities	55,902,000	(93,801,000)
Net increase (decrease) in cash and cash equivalents	58,673,000	(254,012,000)
Cash and cash equivalents at beginning of period	18,693,000	381,869,000
Cash and cash equivalents at end of period	$ 77,366,000	$ 127,857,000

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Fair Value Measurements (Recurring Level 3 Rollforward) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance, beginning of period	$ 23,950,000	$ 16,478,000
Unrealized gains on commodity derivative contracts included in net earnings	5,400,000	310,000
Payments on settlement of commodity derivative contracts	(7,040,000)	(1,442,000)
Balance, end of period	$ 22,310,000	$ 15,346,000

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 77,366,000	$ 18,693,000
Restricted cash	140,131,000	0
Accrued production receivable	303,552,000	294,689,000
Trade and other receivables, net	150,379,000	164,446,000
Short-term investments	0	86,682,000
Derivative assets	23,015,000	47,402,000
Deferred tax assets	47,641,000	50,156,000
Other current assets	15,951,000	22,045,000
Total current assets	758,035,000	684,113,000
Oil and natural gas properties (using full cost accounting)
Proved	7,329,967,000	7,026,579,000
Unevaluated	995,352,000	1,157,106,000
CO2 properties	613,308,000	596,003,000
Pipelines and plants	1,755,679,000	1,701,756,000
Other property and equipment	162,363,000	157,674,000
Less accumulated depletion, depreciation, amortization, and impairment	(2,751,999,000)	(2,627,493,000)
Net property and equipment	8,104,670,000	8,011,625,000
Derivative assets	1,245,000	29,000
Goodwill	1,236,318,000	1,236,318,000
Other assets	241,794,000	252,339,000
Total assets	10,342,062,000	10,184,424,000
Current liabilities
Accounts payable and accrued liabilities	359,141,000	429,336,000
Oil and gas production payable	196,622,000	197,092,000
Derivative liabilities	41,972,000	26,523,000
Current maturities of long-term debt	8,853,000	8,316,000
Total current liabilities	606,588,000	661,267,000
Long-term liabilities
Long-term debt, net of current portion	2,727,700,000	2,669,729,000
Asset retirement obligations	81,935,000	88,726,000
Derivative liabilities	22,013,000	18,872,000
Deferred taxes	1,953,253,000	1,918,576,000
Other liabilities	22,131,000	20,756,000
Total long-term liabilities	4,807,032,000	4,716,659,000
Commitments and contingencies (Note 6)
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	0	0
Common stock, $.001 par value, 600,000,000 shares authorized; 404,722,399 and 402,946,070 issued, respectively	405,000	403,000
Paid-in capital in excess of par	3,102,617,000	3,090,374,000
Retained earnings	2,022,942,000	1,909,475,000
Accumulated other comprehensive loss	(400,000)	(418,000)
Treasury stock, at cost, 14,146,005 and 13,965,673 shares, respectively	(197,122,000)	(193,336,000)
Total stockholders' equity	4,928,442,000	4,806,498,000
Total liabilities and stockholders' equity	$ 10,342,062,000	$ 10,184,424,000

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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Condensed Consolidated Statements of Comprehensive Operations (unaudited) [Abstract]
Net income (loss)	$ 113,467,000	$ (14,190,000)
Other comprehensive income, net of income tax:
Net unrealized gain on available-for-sale securities, net of tax of $2,550	0	4,163,000
Interest rate lock derivative contracts reclassified to income, net of tax of $11 and $11, respectively	18,000	17,000
Total other comprehensive income	18,000	4,180,000
Comprehensive income (loss)	$ 113,485,000	$ (10,010,000)

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Related Party Transactions (Details Textuals) (USD $)	3 Months Ended
	Mar. 31, 2012
Related Party Transaction [Line Items]
Due From Related Parties Future Periods	$ 2,400,000
Lease Expiration Date	2016-07-31
Production Purchase Agreement [Member]
Related Party Transaction [Line Items]
Oil purchases	1,200,000
Related Party Transaction, Description of Transaction	The oil purchased under this agreement is related to the non-core assets in central and southern Mississippi and in southern Louisiana (see further discussion in Note 2, Acquisitions and Divestitures) sold to this same entity. We are under no obligation to purchase oil under this agreement.
Office Lease [Member]
Related Party Transaction [Line Items]
Lease income recognized during the period	$ 27,000
Related Party Transaction, Description of Transaction	a sublease of excess office space

XML

Basis of Presentation (Reconciliation of Weighted Average Shares Table)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Weighted average shares used in the basic and diluted net income per common share
Weighted average common shares - basic	386,367,000	397,386,000
Potentially dilutive securities:
Performance equity Awards	117,000	0
Weighted average common shares - diluted	390,943,000	397,386,000
Stock options and SARs [Member]
Potentially dilutive securities:
Stock options, SARs, and Restricted stock	3,330,000	0
Restricted stock [Member]
Potentially dilutive securities:
Stock options, SARs, and Restricted stock	1,129,000	0

XML

Subsequent Events (Textuals) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Apr. 11, 2012 Paradox Basin [Member]	Apr. 30, 2012 Pending Acquisition of Thompson Field [Member]
Subsequent Event [Line Items]
Anticipated proceeds from sale of oil and natural gas properties			$ 75,000,000
Effective Date Of Transaction	Dec. 01, 2011		Jan. 01, 2012
Proceeds from Sale of Oil and Gas Property and Equipment	166,703,000	11,989,000	72,400,000
Net revenue interest acquired in purchase of oil and natural gas properties				84.70%
Anticipated Payments To Acquire Oil And Gas Property				$ 360,000,000
Net revenue interest retained by seller				5.00%
Gross oil production threshold				3,000
Anticipated Close Date				The acquisition is expected to close in June 2012

XML

Basis of Presentation (Textuals) (USD $) Share data in Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	Jan. 31, 2012	Mar. 31, 2012	Mar. 31, 2011
Basis of Presentation (Textuals) [Abstract]
Weighted average common shares - basic restricted stock		3.9	3.7
Distribution on Vanguard common units			$ 1,800,000
Proceeds from sale of short-term investments	83,500,000	83,545,000	0
Loss on sale of Vanguard securities		$ 3,100,000

XML

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Other comprehensive income, net of income tax:
Tax effect of changes in value on available-for-sale securities	$ 0	$ (2,550,000)
Tax for interest rate lock derivative contracts reclassified to income	$ 11,000	$ 11,000

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Stockholders' equity
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized (actual number)	25,000,000	25,000,000
Preferred stock, shares issued (actual number)	0	0
Preferred stock, shares outstanding (actual number)	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized (actual number)	600,000,000	600,000,000
Common stock, shares issued (actual number)	404,722,399	402,946,070
Treasury stock, shares (actual number)	14,146,005	13,965,673

XML

Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2012

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, 2011. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Interim Financial Statements - Use of Estimates

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management's opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2012,ourconsolidated results of operations for thethree months ended March 31, 2012 and 2011, and our consolidated cash flows for the three months ended March 31, 2012 and 2011. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter. On the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011, “Taxes other than income”is a new line item and includes oil and natural gas ad valorem taxes, which were reclassified from “Lease operating expenses,”franchise taxes and property taxes on buildings, which were reclassified from “General and administrative,” oil and natural gas production taxes, which were reclassified from “Production taxes and marketing expenses” used in prior reports and CO2 property ad valorem and production taxes, which were classified from “CO2 discovery and operating expenses.” Such reclassifications had no impact on our reported total expenses or net income.

Restricted Cash

Restricted Cash

Restricted cash consists of proceeds from the sale of oil and gas properties in February 2012 that are held by aqualified intermediary and are restricted for the pending acquisition of Thompson Field (see Note 8, Subsequent Events) to facilitate an anticipatedlike-kind exchange transaction.

Net Income Per Common Share

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to common 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 to net income and common shares of the potential dilution from stock options, stock appreciation rights (“SARs”), nonvested restricted stock, and nonvested performance equity awards. For thethree months ended March 31, 2012 and 2011, there were no adjustments to net income for purposes of calculating diluted net income per common share.

Basic weighted average common shares excludes 3.9million and 3.7million sharesof nonvested restricted stockduring the three months ended March 31, 2012 and 2011, respectively. 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, the nonvested 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.

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 December 31, 2011, 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 Encore Energy Partners LP to a subsidiary of Vanguard on December 31, 2010. We received distributions of $1.8millionon the Vanguard common units we owned for the three months ended March 31, 2011, which are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. During January 2012, the Company sold its investment in Vanguard for cash consideration of $83.5million, net of related transaction fees. The Company recognized a pretax loss on the sale of $3.1million, which is included in “Other expenses” on our Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012.

Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Comprehensive Income.In June 2011, the Financial Accounting Standards Board (“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 was effective for Denbury beginning January 1, 2012. Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends the Financial Accounting Standards Board Codification (“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 was effective for Denbury beginning January 1, 2012. The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures. See Note 5, Fair Value Measurements.

Derivatives, Policy

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense” 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 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. We only enter into commodity derivative contracts with parties that are lenders under our BankCredit Agreement.

Fair Value of Financial Instruments, Policy

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. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing. The Company's costless-collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

•       Level 3 –Pricing inputs include significant inputs that are generally less observable 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 (i.e., Houston ship channel). The Company's basis swaps are estimated using discounted cash flow calculations based upon forward commodity price curves.Significant increases or decreases in forward commodity price curves would result in a significantly higher or lower fair value measurement.

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

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Document and Entity Information	3 Months Ended
	Mar. 31, 2012
Document And Company Information [Abstract]
Entity Registrant Name	Denbury Resources Inc.
Entity Central Index Key	0000945764
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
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	390,635,689

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Basis of Presentation (Tables)

3 Months Ended

Mar. 31, 2012

Basis of Presentation (Tables) [Abstract]

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

The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:

		Three Months Ended
		March 31,
In thousands		2012	2011
Basic weighted average common shares		386,367	397,386
Potentially dilutive securities:
	Stock options and SARs	3,330	—
	Performance equity awards	117	—
	Restricted stock	1,129	—
Diluted weighted average common shares		390,943	397,386

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

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

		Three Months Ended
		March 31,
In thousands		2012	2011
Stock options and SARs		3,179	12,641
Restricted stock		10	3,453
	Total	3,189	16,094

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Revenues and other income
Oil, natural gas, and related product sales	$ 633,501,000	$ 506,192,000
CO2 sales and transportation fees	6,795,000	4,924,000
Interest income and other income	4,820,000	3,049,000
Total revenues and other income	645,116,000	514,165,000
Expenses
Lease operating expenses	137,964,000	123,797,000
Marketing expenses	10,830,000	5,303,000
CO2 discovery and operating expenses	6,205,000	1,946,000
Taxes other than income	43,694,000	32,483,000
General and administrative	36,607,000	42,319,000
Interest, net of amounts capitalized of $19,445 and $10,957, respectively	36,314,000	48,777,000
Depletion, depreciation, and amortization	120,895,000	93,594,000
Derivatives expense	45,275,000	170,750,000
Loss on early extinguishment of debt	0	15,783,000
Impairment of assets	17,300,000	0
Other expenses	10,720,000	2,359,000
Total expenses	465,804,000	537,111,000
Income (loss) before income taxes	179,312,000	(22,946,000)
Income tax provision (benefit)
Current income taxes	28,708,000	(848,000)
Deferred income taxes	37,137,000	(7,908,000)
Net income (loss)	$ 113,467,000	$ (14,190,000)
Net income (loss) per common share - basic	$ 0.29	$ (0.04)
Net income (loss) per common share - diluted	$ 0.29	$ (0.04)
Weighted average common shares outstanding
Basic	386,367,000	397,386,000
Diluted	390,943,000	397,386,000

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 4. Derivative Instruments

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; 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” 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 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. We only enter into commodity derivative contracts with parties that are lenders under our BankCredit Agreement.

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

			Three Months Ended
			March 31,
In thousands			2012		2011
Oil
	Payment on settlements of derivative contracts		$	8,230	$	5,028
	Fair value adjustments to derivative contracts – expense			42,445		167,064
		Total derivatives expense – oil		50,675		172,092
Natural Gas
	Receipt on settlements of derivative contracts			(7,040)		(6,616)
	Fair value adjustments to derivative contracts – expense			1,640		5,274
		Total derivatives income – natural gas		(5,400)		(1,342)
		Derivatives expense	$	45,275	$	170,750

Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables presentoutstanding commodity derivative contracts with respect to future production as of March 31, 2012:

					Contract Prices(2)
			Type of				Weighted Average Price
Year		Months	Contract	Volume(1)		Range	Swap		Floor		Ceiling
Oil Contracts:
2012		Apr – June	Swap	625	$	80.28 – 81.75	$	81.04	$	—	$	—
			Collar	53,000		70.00 – 137.50		—		70.00		119.44
			Put	625		65.00 – 65.00		—		65.00		—
		Total Apr – June 2012		54,250
		July – Sept	Swap	625	$	80.28 – 81.75	$	81.04	$	—	$	—
			Collar	53,000		80.00 – 140.65		—		80.00		128.57
			Put	625		65.00 – 65.00		—		65.00		—
		Total July – Sept 2012		54,250
		Oct – Dec	Swap	625	$	80.28 – 81.75	$	81.04	$	—	$	—
			Collar	53,000		80.00 – 140.65		—		80.00		128.57
			Put	625		65.00 – 65.00		—		65.00		—
		Total Oct – Dec 2012		54,250
2013		Jan – Mar	Swap	—	$	—	$	—	$	—	$	—
			Collar	55,000		70.00 – 117.00		—		70.00		110.32
			Put	—		—		—		—		—
		Total Jan – Mar 2013		55,000
		Apr – June	Swap	—	$	—	$	—	$	—	$	—
			Collar	50,000		75.00 – 124.20		—		75.00		116.92
			Put	—		—		—		—		—
		Total Apr – June 2013		50,000
		July – Sept	Swap	—	$	—	$	—	$	—	$	—
			Collar	50,000		75.00 – 133.10		—		75.00		122.14
			Put	—		—		—		—		—
		Total July – Sept 2013		50,000
		Oct – Dec	Swap	—	$	—	$	—	$	—	$	—
			Collar	18,000		80.00 – 127.50		—		80.00		126.63
			Put	—		—		—		—		—
		Total Oct – Dec 2013		18,000
Natural Gas Contracts:
2012		Apr – Dec	Swap	20,000	$	6.30 – 6.85	$	6.53	$	—	$	—
			Collar	—		—		—		—		—
			Put	—		—		—		—		—
		Total Apr – Dec 2012		20,000
(1)	Contract volumes are stated in BBl/d and MMBtu/d for oil and natural gas contracts, respectively.
(2)	Contract prices are stated in $/BBl and $/MMBtu for oil and natural gas contracts, respectively.

Additional Disclosures about Derivative Instruments

At March 31,2012 and December 31, 2011, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

					Estimated Fair Value
					Asset (Liability)
In thousands					March 31,		December 31,
Type of Contract				Balance Sheet Location	2012		2011
Derivatives not designated as hedging instruments:
	Derivative asset
		Crude oil contracts		Derivative assets – current	$	705	$	23,452
		Natural gas contracts		Derivative assets – current		22,310		23,950
		Crude oil contracts		Derivative assets – long-term		1,245		29
	Derivative liability
		Crude oil contracts		Derivative liabilities – current		(40,212)		(22,610)
		Deferred premiums(1)		Derivative liabilities – current		(1,760)		(3,913)
		Crude oil contracts		Derivative liabilities – long-term		(22,013)		(18,702)
		Deferred premiums(1)		Derivative liabilities – long-term		—		(170)
			Total derivatives not designated as hedging instruments		$	(39,725)	$	2,036
(1)		Deferred premiums payable relate to various oil and natural gas floor contracts and are payable on a monthly basis through January 2013.

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Long-Term Debt

3 Months Ended

Mar. 31, 2012

Debt Disclosure [Abstract]

Long-Term Debt

Note 3. Long-Term Debt

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

			March 31,		December 31,
In thousands			2012		2011
Bank Credit Facility			$	445,000	$	385,000
9½% Senior Subordinated Notes due 2016, including premium of $11,170 and $11,854, respectively				236,090		236,774
9¾% Senior Subordinated Notes due 2016, including discount of $16,783 and $17,854, respectively				409,567		408,496
8¼% Senior Subordinated Notes due 2020				996,273		996,273
6⅜% Senior Subordinated Notes due 2021				400,000		400,000
Other Subordinated Notes, including premium of $31 and $33, respectively				3,838		3,840
NEJD Pipeline financing				162,704		163,677
Free State Pipeline financing				79,189		79,597
Capital lease obligations				3,892		4,388
	Total			2,736,553		2,678,045
		Less current obligations		(8,853)		(8,316)
	Long-term debt and capital lease obligations		$	2,727,700	$	2,669,729

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. Certain of DRI's subsidiaries guarantee our debt, and each such subsidiary guarantor is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees are full and unconditional and joint and several obligations of the subsidiary guarantors.

Bank Credit Facility

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 party thereto (as amended 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 of each year and upon requested special redeterminations. The borrowing base is adjusted at the banks' discretion and is based in part upon certain external factors over which we have no control. The weighted average interest rate on borrowings under the credit facility, evidenced by the Bank Credit Agreement (the “Bank Credit Facility”) was 2.0% for the three months ended March 31, 2012.We incur a commitment fee on the unused portion of the Bank Credit Facilityof either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base. The Bank Credit Agreementis scheduled to mature in May 2016.

In April 2012, we entered into the Seventh Amendment to the Bank Credit Agreement (the “Bank Amendment”). Under the Bank Amendment, we increased the amount of additional permitted subordinate debt (other than refinancing debt) from $300.0 million to $650.0 million. At the same time, the banks reaffirmed Denbury's borrowing base of $1.6 billion under the Bank Credit Facility until the next redetermination, which is scheduled to occur on or around November 1, 2012.

6⅜% Senior Subordinated Notes due 2021

In February 2011, we issued $400.0 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 $393.0 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notesbelow).

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 7½% Senior Subordinated Notes due 2013 (“2013 Notes”) and all $300.0 million principal amount of our 7½% Senior Subordinated Notes due 2015 (“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 Notes 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$15.8million loss during the three months ended March 31, 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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Basis of Presentation (Anti-dilutive Securities Excluded From Diluted Net EPS)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	3,189,000	16,094,000
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	3,179,000	12,641,000
Restricted stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	10,000	3,453,000

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2012

Debt Disclosure [Abstract]

Components of Long-Term Debt

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

			March 31,		December 31,
In thousands			2012		2011
Bank Credit Facility			$	445,000	$	385,000
9½% Senior Subordinated Notes due 2016, including premium of $11,170 and $11,854, respectively				236,090		236,774
9¾% Senior Subordinated Notes due 2016, including discount of $16,783 and $17,854, respectively				409,567		408,496
8¼% Senior Subordinated Notes due 2020				996,273		996,273
6⅜% Senior Subordinated Notes due 2021				400,000		400,000
Other Subordinated Notes, including premium of $31 and $33, respectively				3,838		3,840
NEJD Pipeline financing				162,704		163,677
Free State Pipeline financing				79,189		79,597
Capital lease obligations				3,892		4,388
	Total			2,736,553		2,678,045
		Less current obligations		(8,853)		(8,316)
	Long-term debt and capital lease obligations		$	2,727,700	$	2,669,729

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Related Party Transactions

3 Months Ended

Mar. 31, 2012

Related Party Transactions Petro Harvester [Abstract]

Related Party Transactions - Petro Harvester

Note 7. Related Party

During the first quarter of 2012, we purchased and marketed $1.2 million of oil produced bya privately-held entity of which a member of our Board of Directors serves as chairman of the board. The oil purchased under this agreement is related to the non-core assets in central and southern Mississippi and in southern Louisiana (see further discussion in Note 2, Acquisitions and Divestitures) sold to this same entity. We are under no obligation to purchase oil under this agreement.

In addition, during the first quarter of 2012, we entered into a sublease of excess office space at our former corporate headquarters with the same privately-held entity. The sublease provides for payment of $2.4 million in lease rentals to us over thelease term, which expires on July 31, 2016. During the first quarter of 2012, we recorded $27 thousand in lease income related to the new sublease arrangement, which is classified as “Interest income and other income” in the Unaudited Condensed Consolidated Statements of Operations.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

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

Fair Value Measurements

Note 5. Fair Value Measurements

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

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

•       Level 2 –Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing. The Company's costless-collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

•       Level 3 –Pricing inputs include significant inputs that are generally less observable 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 (i.e., Houston ship channel). The Company's basis swaps are estimated using discounted cash flow calculations based upon forward commodity price curves.Significant increases or decreases in forward commodity price curves would result in a significantly higher or lower fair value measurement.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. Denbury uses 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
March 31, 2012
Assets
	Oil and natural gas derivative contracts		$	—	$	1,950	$	22,310	$	24,260
Liabilities
	Oil and natural gas derivative contracts			—		(62,225)		—		(62,225)
		Total	$	—	$	(60,275)	$	22,310	$	(37,965)
December 31, 2011
Assets
	Short-term investments		$	86,682	$	—	$	—	$	86,682
	Oil and natural gas derivative contracts			—		23,481		23,950		47,431
Liabilities
	Oil and natural gas derivative contracts			—		(41,312)		—		(41,312)
		Total	$	86,682	$	(17,831)	$	23,950	$	92,801

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

Level 3 Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table summarizes the changes in the fair value of our Level 3 assets for the three months endedMarch 31, 2012 and 2011:

		Three Months Ended
		March 31,
In thousands		2012		2011
Balance, beginning of period		$	23,950	$	16,478
	Unrealized gains on commodity derivative contracts included in earnings		5,400		310
	Payments on settlement of commodity derivative contracts		(7,040)		(1,442)
Balance, end of period		$	22,310	$	15,346

We utilize an income approach to value our natural gas swap arrangements, generally the industry standard valuation technique for a commodity swap contract. We obtain and ensure the appropriateness of the natural gas forward pricing curve, the most significant input to the calculation, and the fair value estimate is prepared and reviewed on a quarterly basis.

The following table details fair value inputs related to our level 3 financial measurements:

In thousands		Fair Value at 3/31/2012		Valuation Technique(s)	Unobservable Input	Range
Oil and natural gas derivative contracts		$	22,310	Discounted Cash Flow	Forward commodity price curve	(a)
(a)	The derivative instruments detailed in this category include non-exchange-traded natural gas derivatives swaps that are valued based on regional pricing other than NYMEX. The regional pricing sources utilized for these instruments include the following (forward pricing ranges represent the high and low price expected to be received within the settlement period):
	Pricing Index		Settlement Period		Forward Pricing Range
	TETCO M1		4/1/2012 – 12/31/2012		$2.09/MMBtu – $3.21/MMBtu
	Houston Ship Channel		4/1/2012 – 12/31/2012		$2.06/MMBtu – $3.09/MMBtu
	Natural Gas – Midcontinent		4/1/2012 – 12/31/2012		$1.98/MMBtu – $3.05/MMBtu

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

As of December 31, 2011, we had invested a total of $13.8 million in the preferred stock of Faustina Hydrogen Products LLC, a company created to develop a proposed gasification plant from which CO2 would be produced as a byproduct and used by Denbury in its tertiary oil operations. The investment was recorded at cost, together with a $1.3 million receivable for accrued dividends receivable. The developer of the proposed plant was soliciting other potential investors for the project, and as of December 31, 2011, a third-party was actively engaged in due diligence.  During 2012, a key investor and participant in the project announced its intent to abandon its investment in the proposed plant. As a result, due diligence by the potential third party investor ceased. Absent the key investor, we believe it is unlikely the plant will be constructed and therefore, it is also unlikely our investment will generate future cash flows. Accordingly, we recorded a $15.1 million impairment charge for this investment during the first quarter of 2012, which is classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statements of Operations. The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset. These inputs are unobservable within the marketplace and therefore considered level 3 within the fair value hierarchy. However, as there are currently no expected future cash flows associated with the plant, the fair value was determined to be $0.

Other Fair Value Measurements

The carrying value of our Bank Credit Facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our senior subordinated notes as of March 31, 2012 and December 31, 2011 is $2,255.5 million and $2,253.2 million, respectively. The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets). We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 6. Commitments and Contingencies

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

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Subsequent Events

3 Months Ended

Mar. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

Note 8. Subsequent Events

Sale of Non-Core Assets

On April 11, 2012, we announced that we had entered into an agreement and closed on the sale of certain non-operated assets in the Paradox Basin of Utah for $75 million. The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million. Preliminary closing adjustments include operating net revenues after January 1, 2012, net of capital expenditures, along with other purchase price adjustments.

Amendment to Bank Credit Agreement

During April 2012, we entered into an amendment to our Bank Credit Agreement (see Note 3, Long-Term Debt).

Pending Acquisition of Thompson Field

In April 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash. Under the agreement, the seller will hold approximately a 5% net revenue interest beginning when average monthly tertiary oil production exceeds 3,000 Bbls/d. Thompson Field is a significant potential tertiary oil flood located approximately 18 miles west of our Hastings Field, our most recent CO2 flood.The acquisition is expected to close inJune 2012.

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Fair Value Measurements (Textuals) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Fair Value Measurements (details) [Abstract]
Long-term Debt, Fair Value	$ 2,255,500,000		$ 2,253,200,000
Held-to-maturity Securities, Debt Maturities, Net Carrying Amount			13,800,000
Accrued dividends receivable			1,300,000
Held-to-maturity Securities, Fair Value Disclosure	0
Components Of Impairment Nonoperating [Line Items]
Other Asset Impairment Charges	17,300,000	0
Faustina Investment Impairment [Member]
Components Of Impairment Nonoperating [Line Items]
Other Asset Impairment Charges	$ 15,100,000

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

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

Fair value hierarchy of financial assets and liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:

			Fair Value Measurements Using:
					Significant
			Quoted Prices		Other		Significant
			in Active		Observable		Unobservable
			Markets		Inputs		Inputs
In thousands			(Level 1)		(Level 2)		(Level 3)		Total
March 31, 2012
Assets
	Oil and natural gas derivative contracts		$	—	$	1,950	$	22,310	$	24,260
Liabilities
	Oil and natural gas derivative contracts			—		(62,225)		—		(62,225)
		Total	$	—	$	(60,275)	$	22,310	$	(37,965)
December 31, 2011
Assets
	Short-term investments		$	86,682	$	—	$	—	$	86,682
	Oil and natural gas derivative contracts			—		23,481		23,950		47,431
Liabilities
	Oil and natural gas derivative contracts			—		(41,312)		—		(41,312)
		Total	$	86,682	$	(17,831)	$	23,950	$	92,801

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

The following table summarizes the changes in the fair value of our Level 3 assets for the three months endedMarch 31, 2012 and 2011:

		Three Months Ended
		March 31,
In thousands		2012		2011
Balance, beginning of period		$	23,950	$	16,478
	Unrealized gains on commodity derivative contracts included in earnings		5,400		310
	Payments on settlement of commodity derivative contracts		(7,040)		(1,442)
Balance, end of period		$	22,310	$	15,346

Quantitative valuation techniques for assets and liabilities measured on a recurring basis (Level 3)

The following table details fair value inputs related to our level 3 financial measurements:

In thousands		Fair Value at 3/31/2012		Valuation Technique(s)	Unobservable Input	Range
Oil and natural gas derivative contracts		$	22,310	Discounted Cash Flow	Forward commodity price curve	(a)
(a)	The derivative instruments detailed in this category include non-exchange-traded natural gas derivatives swaps that are valued based on regional pricing other than NYMEX. The regional pricing sources utilized for these instruments include the following (forward pricing ranges represent the high and low price expected to be received within the settlement period):
	Pricing Index		Settlement Period		Forward Pricing Range
	TETCO M1		4/1/2012 – 12/31/2012		$2.09/MMBtu – $3.21/MMBtu
	Houston Ship Channel		4/1/2012 – 12/31/2012		$2.06/MMBtu – $3.09/MMBtu
	Natural Gas – Midcontinent		4/1/2012 – 12/31/2012		$1.98/MMBtu – $3.05/MMBtu

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Long-Term Debt (Components of Long-Term Debt) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Bank Credit Facility	$ 445,000,000	$ 385,000,000
Capital Lease Obligations	3,892,000	4,388,000
Total	2,736,553,000	2,678,045,000
Less current obligations	(8,853,000)	(8,316,000)
Long-term debt and capital lease obligations	2,727,700,000	2,669,729,000
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	236,090,000	236,774,000
Including premium of	11,170,000	11,854,000
Debt Instrument, Interest Rate, Stated Percentage	9.50%
9.75% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	409,567,000	408,496,000
Including discount of	16,783,000	17,854,000
Debt Instrument, Interest Rate, Stated Percentage	9.75%
6 3/8% Senior Subordinated Notes Due 2021 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	400,000,000	400,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.375%
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	996,273,000	996,273,000
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Other Subordinated Notes [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	3,838,000	3,840,000
Including premium of	31,000	33,000
NEJD Financing [Member]
Debt Instrument [Line Items]
Financing Lease Obligations	162,704,000	163,677,000
Free State Financing [Member]
Debt Instrument [Line Items]
Financing Lease Obligations	$ 79,189,000	$ 79,597,000

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Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Expenses
Interest capitalized	$ 19,445,000	$ 10,957,000

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Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2012

Acquisitions and Divestitures [Abstract]

Acquisitions and Divestitures

Note 2. Acquisitions and Divestitures

Acquisitions

August 2011 Acquisition of Reservesin Rocky Mountain Region at Riley Ridge

InAugust 2011, we acquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming.RileyRidge contains natural gas resources, as well as helium and CO2resources. The purchase included a57.5% interest in a gas plant which will separate the helium and natural gas from the commingled gas stream, and interests in certain surrounding properties.The purchase price was approximately $214.8 million after closing adjustments, including a $15.0 million deferred payment to be made at the time the Riley Ridge gas plant is operational and meets specific performance conditions. The gas plant is currently undergoing readiness testing, and we expect it to become operational during the fourth quarter of 2012.

The August 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2011.Because the Riley Ridge plant is not yet operational, current production at the field is negligible. As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011.

Divestitures

On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million. We entered into the sales agreement with a privately held entity in which a member of our Board of Directors serves as chairman of the board, in a sale for which there was a competing bid contained in a multi-property purchase proposal. On February 29, 2012, we closed on the sale with net proceeds of $144.8 million, after preliminary closing adjustments. The sale had an effective date of December 1, 2011 and consequently, operating net revenues after the effective date, net of capital expenditures, along with any other purchase price adjustments, were adjustments to the selling price. We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.

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Long Term Debt (Textuals) (USD $)	1 Months Ended	3 Months Ended			3 Months Ended			2 Months Ended	3 Months Ended		2 Months Ended	3 Months Ended	1 Months Ended
	Mar. 31, 2010	Mar. 31, 2012	Mar. 31, 2011	Apr. 30, 2012	Mar. 31, 2012 Minimum [Member]	Mar. 31, 2012 Maximum [Member]	Feb. 03, 2011 7.5% Senior Subordinated Notes due 2013 [Member]	Mar. 03, 2011 7.5% Senior Subordinated Notes due 2013 [Member] Extinguishment One [Member]	Apr. 01, 2011 7.5% Senior Subordinated Notes due 2013 [Member] Extinguishment Two [Member]	Feb. 03, 2011 7.5% Senior Subordinated Notes due 2015 [Member]	Mar. 03, 2011 7.5% Senior Subordinated Notes due 2015 [Member] Extinguishment One [Member]	Mar. 21, 2011 7.5% Senior Subordinated Notes due 2015 [Member] Extinguishment Two [Member]	Feb. 28, 2011 6 3/8% Senior Subordinated Notes Due 2021 [Member]
$1.6 Billion Revolving Credit Facility [Abstract]
Initiation date of Bank Credit Facility	March 2010
Borrowing Base of Denbury credit facility	$ 1,600,000,000			$ 1,600,000,000
Maturity date of Denbury Credit Facility		May 2016
Commitment fee on Bank Credit Facility		We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base.
Weighted average interest rate on Bank Credit Facility		2.00%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage					0.375%	0.50%
Permissable amount of additional subordinated debt		300,000,000		650,000,000
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries		100.00%
Face Value of Notes Issued							225,000,000			300,000,000			400,000,000
Selling Price Of Debt Instrument													100.00%
Proceeds from issuance of subordinated long term debt, net of commissions and fees													393,000,000
Principal amount of notes for which cash tender offers commenced							225,000,000			300,000,000			400,000,000
Extinguishment of Debt [Line Items]
Amount of debt repaid or repurchased								169,600,000	55,400,000		220,900,000	79,100,000
Percentage of par at which debt was repurchased								100.625%	100.00%		104.125%	103.75%
Loss on early extinguishment of debt		$ 0	$ 15,783,000

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities (Tables) [Abstract]

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

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

			Three Months Ended
			March 31,
In thousands			2012		2011
Oil
	Payment on settlements of derivative contracts		$	8,230	$	5,028
	Fair value adjustments to derivative contracts – expense			42,445		167,064
		Total derivatives expense – oil		50,675		172,092
Natural Gas
	Receipt on settlements of derivative contracts			(7,040)		(6,616)
	Fair value adjustments to derivative contracts – expense			1,640		5,274
		Total derivatives income – natural gas		(5,400)		(1,342)
		Derivatives expense	$	45,275	$	170,750

Commodity derivative contracts not classified as hedging instruments

The following tables presentoutstanding commodity derivative contracts with respect to future production as of March 31, 2012:

					Contract Prices(2)
			Type of				Weighted Average Price
Year		Months	Contract	Volume(1)		Range	Swap		Floor		Ceiling
Oil Contracts:
2012		Apr – June	Swap	625	$	80.28 – 81.75	$	81.04	$	—	$	—
			Collar	53,000		70.00 – 137.50		—		70.00		119.44
			Put	625		65.00 – 65.00		—		65.00		—
		Total Apr – June 2012		54,250
		July – Sept	Swap	625	$	80.28 – 81.75	$	81.04	$	—	$	—
			Collar	53,000		80.00 – 140.65		—		80.00		128.57
			Put	625		65.00 – 65.00		—		65.00		—
		Total July – Sept 2012		54,250
		Oct – Dec	Swap	625	$	80.28 – 81.75	$	81.04	$	—	$	—
			Collar	53,000		80.00 – 140.65		—		80.00		128.57
			Put	625		65.00 – 65.00		—		65.00		—
		Total Oct – Dec 2012		54,250
2013		Jan – Mar	Swap	—	$	—	$	—	$	—	$	—
			Collar	55,000		70.00 – 117.00		—		70.00		110.32
			Put	—		—		—		—		—
		Total Jan – Mar 2013		55,000
		Apr – June	Swap	—	$	—	$	—	$	—	$	—
			Collar	50,000		75.00 – 124.20		—		75.00		116.92
			Put	—		—		—		—		—
		Total Apr – June 2013		50,000
		July – Sept	Swap	—	$	—	$	—	$	—	$	—
			Collar	50,000		75.00 – 133.10		—		75.00		122.14
			Put	—		—		—		—		—
		Total July – Sept 2013		50,000
		Oct – Dec	Swap	—	$	—	$	—	$	—	$	—
			Collar	18,000		80.00 – 127.50		—		80.00		126.63
			Put	—		—		—		—		—
		Total Oct – Dec 2013		18,000
Natural Gas Contracts:
2012		Apr – Dec	Swap	20,000	$	6.30 – 6.85	$	6.53	$	—	$	—
			Collar	—		—		—		—		—
			Put	—		—		—		—		—
		Total Apr – Dec 2012		20,000
(1)	Contract volumes are stated in BBl/d and MMBtu/d for oil and natural gas contracts, respectively.
(2)	Contract prices are stated in $/BBl and $/MMBtu for oil and natural gas contracts, respectively.

Derivative financial instruments included in our Unaudited Condensed Consolidated Balance Sheet

At March 31,2012 and December 31, 2011, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

					Estimated Fair Value
					Asset (Liability)
In thousands					March 31,		December 31,
Type of Contract				Balance Sheet Location	2012		2011
Derivatives not designated as hedging instruments:
	Derivative asset
		Crude oil contracts		Derivative assets – current	$	705	$	23,452
		Natural gas contracts		Derivative assets – current		22,310		23,950
		Crude oil contracts		Derivative assets – long-term		1,245		29
	Derivative liability
		Crude oil contracts		Derivative liabilities – current		(40,212)		(22,610)
		Deferred premiums(1)		Derivative liabilities – current		(1,760)		(3,913)
		Crude oil contracts		Derivative liabilities – long-term		(22,013)		(18,702)
		Deferred premiums(1)		Derivative liabilities – long-term		—		(170)
			Total derivatives not designated as hedging instruments		$	(39,725)	$	2,036
(1)		Deferred premiums payable relate to various oil and natural gas floor contracts and are payable on a monthly basis through January 2013.