DENBURY INC - Quarter Report: 2011 March (Form 10-Q)

DENBURY INC - Quarter Report: 2011 March (Form 10-Q)

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e10vq

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, 2011


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

For the transition period from to

Commission file number: 001-12935

DENBURY RESOURCES INC.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdictions of incorporation or organization)		20-0467835 (I.R.S. Employer Identification No.)

5320 Legacy Drive Plano, TX (Address of principal executive offices)		75024 (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):

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 29, 2011

Common Stock, $.001 par value		401,887,373

DENBURY RESOURCES INC.

INDEX


	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010		3

Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010		4

Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010		5

Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three Months Ended March 31, 2011 and 2010		6

Notes to Unaudited Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

Item 3. Quantitative and Qualitative Disclosures about Market Risk		37

Item 4. Controls and Procedures		38

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		39

Item 1A. Risk Factors		39

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39

Item 6. Exhibits		39

Signatures		40
EX-10.A
EX-10.B
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except par value and share data)


	March 31,			December 31,

	2011			2010
ASSETS

Current assets

Cash and cash equivalents	$	127,857		$	381,869

Accrued production receivable		264,150			223,584

Trade and other receivables, net of allowance of $471 and $456, respectively		138,026			114,149

Short-term investments		99,733			93,020

Derivative assets		19,345			24,242

Deferred tax assets		72,552			27,454


Total current assets		721,663			864,318


Property and equipment

Oil and natural gas properties (using full cost accounting)

Proved		6,238,629			6,042,442

Unevaluated		912,267			870,130

CO₂ and other non-hydrocarbon gases - properties and pipelines		1,940,392			1,901,662

Other property and equipment		132,692			120,641

Less accumulated depletion, depreciation, amortization, and impairment		(2,295,952	)		(2,197,517	)


Net property and equipment		6,928,028			6,737,358


Derivative assets		9,203			12,919

Goodwill		1,232,418			1,232,418

Other assets		220,107			218,050


Total assets	$	9,111,419		$	9,065,063


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities

Accounts payable and accrued liabilities	$	246,145		$	345,998

Oil and gas production payable		161,471			143,145

Derivative liabilities		218,341			78,184

Current maturities of long-term debt		8,446			7,948

Other liabilities		4,070			4,070


Total current liabilities		638,473			579,345


Long-term liabilities

Long-term debt, net of current portion		2,344,781			2,416,208

Asset retirement obligations		83,576			81,290

Derivative liabilities		47,745			29,687

Deferred taxes		1,589,912			1,547,992

Other liabilities		25,567			29,834


Total long-term liabilities		4,091,581			4,105,011


Commitments and contingencies (Note 7)

Stockholders’ equity

Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding		-			-

Common stock, $.001 par value, 600,000,000 shares authorized; 402,155,781 and 400,291,033 shares issued, respectively		402			400

Paid-in capital in excess of par		3,061,793			3,045,937

Retained earnings		1,321,952			1,336,142

Accumulated other comprehensive income (loss)		3,692			(488	)

Treasury stock, at cost, 298,707 and 78,524 shares, respectively		(6,474	)		(1,284	)


Total stockholders’ equity		4,381,365			4,380,707


Total liabilities and stockholders’ equity	$	9,111,419		$	9,065,063

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Three Months Ended

	March 31,

	2011			2010

Revenues and other income

Oil, natural gas, and related product sales	$	506,192		$	330,886

CO₂ sales and transportation fees		4,924			4,497

Gain on sale of interests in Genesis		-			101,568

Interest income and other income		3,049			1,870


Total revenues and other income		514,165			438,821


Expenses

Lease operating expenses		127,097			96,220

Production taxes and marketing expenses		32,751			19,317

CO₂ discovery and operating expenses		2,154			1,368

General and administrative		43,846			32,709

Interest, net of amounts capitalized of $10,957 and $21,312, respectively		48,777			26,416

Depletion, depreciation, and amortization		93,594			81,872

Derivatives expense (income)		170,750			(41,225	)

Loss on early extinguishment of debt		15,783			-

Transaction and other costs related to the Encore Merger		2,359			44,999


Total expenses		537,111			261,676


Income (loss) before income taxes		(22,946	)		177,145

Income tax provision (benefit)

Current income taxes		(848	)		669

Deferred income taxes		(7,908	)		76,272


Consolidated net income (loss)		(14,190	)		100,204

Less: net income attributable to noncontrolling interest		-			(3,316	)


Net income (loss) attributable to Denbury stockholders	$	(14,190	)	$	96,888


Net income (loss) per common share

Basic	$	(0.04	)	$	0.33

Diluted	$	(0.04	)	$	0.32

Weighted average common shares outstanding

Basic		397,386			294,143

Diluted		397,386			299,224

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Three Months Ended

	March 31,

	2011			2010

Cash flows from operating activities

Consolidated net income (loss)	$	(14,190	)	$	100,204

Adjustments needed to reconcile to net cash provided by operating activities

Depletion, depreciation, and amortization		93,594			81,872

Deferred income taxes		(7,908	)		76,272

Gain on sale of interests in Genesis		-			(101,568	)

Stock-based compensation		10,201			7,806

Non-cash fair value derivative adjustments		172,338			(101,026	)

Loss on early extinguishment of debt		15,783			-

Other, net		1,399			2,410

Changes in operating assets and liabilities:

Accrued production receivable		(44,243	)		(12,125	)

Trade and other receivables		(20,160	)		30,854

Other assets		(5,773	)		(2,775	)

Accounts payable and accrued liabilities		(90,382	)		21,971

Oil and natural gas production payable		18,770			13,394

Other liabilities		(4,597	)		(4,121	)


Net cash provided by operating activities		124,832			113,168


Cash flows used for investing activities
Oil and natural gas capital expenditures		(190,296	)		(92,647	)

Acquisitions of oil and natural gas properties		(29,801	)		(340	)

Cash paid in Encore Merger, net of cash acquired		-			(801,489	)

CO₂ and other non-hydrocarbon gases - capital expenditures, including pipelines		(66,157	)		(72,647	)

Deposit received on divesture of Southern Assets		-			45,000

Net proceeds from sale of interests in Genesis		-			162,622

Other		1,211			(4,826	)


Net cash used for investing activities		(285,043	)		(764,327	)


Cash flows from financing activities
Bank repayments		(130,000	)		(625,000	)

Bank borrowings		130,000			1,025,000

Repayment of senior subordinated notes		(469,552	)		(508,182	)

Premium paid on repayment of senior subordinated notes		(13,137	)		(6,257	)

Net proceeds from issuance of senior subordinated notes		400,000			1,000,000

Escrowed funds for redemption of senior subordinated notes		-			(65,566	)

Costs of debt financing		(8,441	)		(76,129	)

Other		(2,671	)		(4,113	)


Net cash provided by (used for) financing activities		(93,801	)		739,753


Net increase (decrease) in cash and cash equivalents		(254,012	)		88,594

Cash and cash equivalents at beginning of period		381,869			20,591


Cash and cash equivalents at end of period	$	127,857		$	109,185

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)


	Three Months Ended

	March 31,

	2011			2010

Consolidated net income (loss)	$	(14,190	)	$	100,204

Other comprehensive income (loss), net of income tax:

Net unrealized gains 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 in each period		17			17

Change in deferred hedge loss on interest rate swaps, net of tax of $10		-			(27	)


Consolidated comprehensive income (loss)		(10,010	)		100,194

Less: comprehensive income attributable to noncontrolling interest		-			(3,285	)


Comprehensive income (loss) attributable to Denbury stockholders	$	(10,010	)	$	96,909

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of March 31, 2011, our consolidated results of operations for the three months ended March 31, 2011 and 2010, and our consolidated cash flows for the three months ended March 31, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Noncontrolling Interest

From March 9, 2010 through December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP’s general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010 we sold all of our ownership interests in ENP and, therefore, we have not consolidated ENP in our Unaudited Condensed Consolidated Balance Sheets as of December 31, 2010, nor do our Unaudited Condensed Consolidated Statement of Operations or Cash Flows for the three months ended March 31, 2011 include ENP’s results of operations or cash flows. As presented in the Unaudited Condensed Consolidated Statement of Operations for the three months ended March 31, 2010, “Net income attributable to noncontrolling interest” of $3.3 million represents ENP’s results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to our stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three months ended March 31, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the periods indicated:

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements


	Three Months Ended
	March 31,

In thousands	2011		2010

Basic weighted average common shares		397,386		294,143
Potentially dilutive securities:
Stock options and SARs		-		3,690
Performance equity awards		-		477
Restricted stock		-		914

Diluted weighted average common shares		397,386		299,224

Basic weighted average common shares excludes 3.5 million shares and 3.4 million shares at March 31, 2011 and 2010, respectively, of unvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant. For purposes of calculating diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

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


	Three Months Ended

	March 31,

In thousands	2011		2010

Stock options and SARs		12,641		5,465
Restricted stock		3,453		1,371

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 March 31, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million, and under the terms of the sale agreement with Vanguard we are restricted from divesting these Vanguard common units until July 31, 2011. In the first quarter of 2011 we received distributions of $1.8 million on the Vanguard common units we own which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statement of Operations for the three months ended March 31, 2011. The unrealized gain on our short-term investment of $4.2 million, net of taxes of $2.6 million, is included in our Unaudited Condensed Consolidated Statement of Comprehensive Operations for the three months ended March 31, 2011.

Recently Adopted Accounting Pronouncements

We have reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2011, and have determined that none would have a material impact to our Unaudited Condensed Consolidated Financial Statements.

Note 2. Acquisitions and Divestitures

2010 Merger with Encore Acquisition Company

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

For the period from the March 9, 2010 Encore acquisition date to March 31, 2010, we recognized $59.7 million and $43.9 million of oil, natural gas and related product sales and field operating income (oil, natural gas and related product sales less lease operating expenses and production taxes and marketing expenses), respectively, related to the Encore Merger. We recognized a total of $2.4 million and $45.0 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration, and severance costs) for the three months ended March 31, 2011, and 2010, respectively.

2010 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge

In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after preliminary closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO₂ resources. The purchase includes a working interest in a gas plant, which is currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also includes approximately 33% of the CO₂ mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit. We own a non-operating interest in those 28,000 acres.

The acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. The purchase price allocation for the acquisition of interests in Riley Ridge Field is preliminary and subject to revision pending finalization of closing adjustments. The following table presents a summary of the preliminary fair value of assets acquired:


In thousands

Oil and natural gas properties	$	19,646
CO₂ and other non-hydrocarbon gases - properties and pipelines (CO₂ properties)		10,907
CO₂ and other non-hydrocarbon gases - properties and pipelines (Riley Ridge plant)		72,070
Prepaid construction and drilling costs		9,346
Other assets		19,300
Asset retirement obligations		(472	)
Goodwill		1,460

Total	$	132,257

Pro Forma Information

Had the Encore Merger and Riley Ridge acquisition both occurred on January 1, 2010, our combined pro forma revenue and net income for the three months ended March 31, 2010, would have been as follows:


In thousands, except per share amounts

Pro forma total revenues	$	615,271
Pro forma net income attributable to Denbury stockholders		112,489
Pro forma net income per common share:
Basic	$	0.28
Diluted		0.28

2010 Sale of Interests in Genesis

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

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 as of the periods indicated:


	March 31,		December 31,

In thousands	2011		2010

Bank Credit Agreement	$	-	$	-

7¹/2% Senior Subordinated Notes due 2013, including discount of $96 and $437, respectively⁽¹⁾		55,352		224,563

7¹/2% Senior Subordinated Notes due 2015, including premium of $427		-		300,427
9¹/2% Senior Subordinated Notes due 2016, including premium of $13,906 and $14,589, respectively		238,826		239,509

9³/4% Senior Subordinated Notes due 2016, including discount of $21,067 and $22,139, respectively		405,283		404,211

8¹/4% Senior Subordinated Notes due 2020		996,273		996,273

6³/8% Senior Subordinated Notes due 2021		400,000		-

Other Subordinated Notes, including premium of $39 and $41, respectively		3,845		3,848

NEJD financing		166,452		167,331

Free State financing		80,979		81,188

Capital lease obligations		6,217		6,806


Total		2,353,227		2,424,156

Less current obligations		8,446		7,948


Long-term debt and capital lease obligations	$	2,344,781	$	2,416,208


(1)		These notes were repurchased on April 1, 2011.

Bank Credit Agreement

On March 9, 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and 23 other lenders as party thereto (the “Bank Credit Agreement”) with a maturity date of March 2014. Availability under the Bank Credit Agreement is subject to a borrowing base (currently $1.6 billion) which is re-determined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. We expect our semi-annual redetermination to be finalized in mid-May 2011. We currently do not anticipate any reduction in our borrowing base as a result of this redetermination.

The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months. We incur a commitment fee of 0.5% on the unused portion of the credit facility or if less, the borrowing base. Loans under the Bank Credit Agreement mature in March 2014. We had no borrowings outstanding on the Bank Credit Agreement as of March 31, 2011.

6³/8% Senior Subordinated Notes due 2021

In February 2011, we issued $400 million of 6³/₈% 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 approximately $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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

Redemption of our 2013 and 2015 Notes

On February 3, 2011, we commenced cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. By March 3, 2011, upon expiration of the tender offers, 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 for 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and repurchasing all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. During the first quarter of 2011, we recognized a $15.8 million loss associated with the first quarter of 2011 debt repurchases, which is included in our income statement under the caption “Loss on early extinguishment of debt”.

Note 4. Derivative Instruments and Hedging Activities

Oil and Natural Gas Derivative Contracts

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

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

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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


	Three Months Ended

	March 31,
In thousands	2011			2010
Oil
Payment on settlements of derivative contracts	$	5,028		$	63,550
Fair value adjustments to derivative contracts - expense (income)		167,064			(61,821	)

Total derivative expense - oil		172,092			1,729
Natural Gas
Receipt on settlements of derivative contracts		(6,616	)		(3,749	)
Fair value adjustments to derivative contracts - expense (income)		5,274			(39,018	)

Total derivative income - natural gas		(1,342	)		(42,767	)
Ineffectiveness on interest rate swaps		-			(187	)

Derivative expense (income)	$	170,750		$	(41,225	)

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables present the fair value of our commodity derivative contracts:


											Estimated Fair Value

					NYMEX Contract Prices Per Bbl						Asset (Liability)

		Type of			Weighted Average Price						March 31,			December 31,

Year	Months	Contract	Bbls/d		Swap		Floor		Ceiling		2011			2010
											(In thousands)
Oil Contracts:
2011	Jan - Mar	Swap		625	$	79.18	$	-	$	-	$	-		$	(737	)
		Collar		43,500		-		67.25		95.80		-			(3,656	)
		Put		6,625		-		69.53		-		-			79

Total Jan - Mar 2011				50,750								-			(4,314	)


	Apr - June	Swap		625		79.18		-		-		(1,593	)		(827	)
		Collar		43,500		-		70.34		100.20		(34,918	)		(12,113	)
		Put		6,625		-		69.53		-		16			499

Total Apr - June 2011				50,750								(36,495	)		(12,441	)


	July - Sept	Swap		625		79.18		-		-		(1,656	)		(865	)
		Collar		42,500		-		70.35		100.09		(48,434	)		(17,308	)
		Put		6,625		-		69.53		-		170			1,026

Total July - Sept 2011				49,750								(49,920	)		(17,147	)


	Oct - Dec	Swap		625		79.18		-		-		(1,658	)		(871	)
		Collar		45,500		-		70.33		101.74		(53,941	)		(18,878	)
		Put		6,625		-		69.53		-		477			1,445

Total Oct - Dec 2011				52,750								(55,122	)		(18,304	)


2012	Jan - Mar	Swap		625		81.04		-		-		(1,502	)		(741	)
		Collar		52,000		-		70.00		106.86		(55,070	)		(19,065	)
		Put		625		-		65.00		-		51			123

Total Jan - Mar 2012				53,250								(56,521	)		(19,683	)


	Apr-June	Swap		625		81.04		-		-		(1,450	)		(726	)
		Collar		53,000		-		70.00		119.44		(29,230	)		(3,288	)
		Put		625		-		65.00		-		78			151

Total Apr - June 2012				54,250								(30,602	)		(3,863	)


	July-Sept	Swap		625		81.04		-		-		(1,402	)		(719	)
		Collar		48,000		-		80.00		127.70		(6,663	)		-
		Put		625		-		65.00		-		103			178

Total July - Sept 2012				49,250								(7,962	)		(541	)


	Oct - Dec	Swap		625		81.04		-		-		(1,356	)		(709	)
		Collar		48,000		-		80.00		127.70		(6,014	)		-
		Put		625		-		65.00		-		117			191

Total Oct - Dec 2012				49,250								(7,253	)		(518	)



Total Oil Contracts											$	(243,875	)	$	(76,811	)

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements


											Estimated Fair Value

					Contract Prices Per MMBtu						Asset (Liability)

		Type of			Weighted Average Price						March 31,			December 31,

Year	Months	Contract	MMBtu/d		Swap		Floor		Ceiling		2011			2010
											(In thousands)
Natural Gas Contracts:
2011	Jan - Mar	Swap		33,500	$	6.27	$	-	$	-	$	-		$	5,846

Total Jan-Mar 2011				33,500								-			5,846


	Apr-Jun	Swap		33,500		6.27		-		-		5,841			5,637

Total Apr-June 2011				33,500								5,841			5,637


	July - Sept	Swap		33,500		6.27		-		-		5,327			5,300

Total July-Sept 2011				33,500								5,327			5,300


	Oct - Dec	Swap		33,500		6.27		-		-		4,615			4,409

Total Oct - Dec 2011				33,500								4,615			4,409


2012	Jan - Dec	Swap		20,000		6.53		-		-		11,753			11,618

Total Jan - Dec 2012				20,000								11,753			11,618

Total Natural Gas Contracts												27,536			32,810


Total Commodity Derivative Contracts											$	(216,339	)	$	(44,001	)

As of March 31, 2011 and December 31, 2010, we had $21.2 million and $26.7 million, respectively, of deferred premiums payable, which relate to various oil and natural gas floor contracts and are payable on a monthly basis from April 2011 to January 2013. These premiums are excluded from the above tables.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Additional Disclosures about Derivative Instruments

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


		Estimated Fair Value
		Asset (Liability)
		March 31,		December 31,
Type of Contract	Balance Sheet Location	2011		2010
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative asset:
Oil contracts	Derivative assets - current	$	714	$	3,050
Natural gas contracts	Derivative assets - current		18,631		21,192
Oil contracts	Derivative assets - long-term		298		1,301
Natural gas contracts	Derivative assets - long-term		8,905		11,618

Derivative liability:
Oil contracts	Derivative liabilities - current		(198,772)		(55,256)
Deferred premiums	Derivative liabilities - current		(19,569)		(22,928)
Oil contracts	Derivative liabilities - long-term		(46,115)		(25,906)
Deferred premiums	Derivative liabilities - long-term		(1,630)		(3,781)

Total derivatives not designated as hedging instruments		$	(237,538)	$	(70,710)

Note 5. Fair Value Measurements

Fair Value Hierarchy

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

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

	•		Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2011
Assets:
Short-term investments	$	99,733	$	-	$	-	$	99,733
Oil and natural gas derivative contracts		-		13,202		15,346		28,548
Liabilities:
Oil and natural gas derivative contracts		-		(244,887)		-		(244,887)

Total	$	99,733	$	(231,685)	$	15,346	$	(116,606)


December 31, 2010
Assets:
Short-term investments	$	93,020	$	-	$	-	$	93,020
Oil derivative contracts		-		20,683		16,478		37,161
Liabilities:
Oil and natural gas derivative contracts		-		(81,162)		-		(81,162)

Total	$	93,020	$	(60,479)	$	16,478	$	49,019

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three months ended March 31, 2011 and 2010:


	Fair Value Measurements Using Significant

	Unobservable Inputs (Level 3)

	Three Months Ended		Three Months Ended

In thousands	March 31, 2011		March 31, 2010
Balance, beginning of period	$	16,478	$	-
Unrealized gains on commodity derivative contracts included in earnings		310		14,773
Commodity derivative contracts acquired from Encore		-		38,093
Receipts on settlement of commodity derivative contracts		(1,442)		(2,348)

Balance, end of period	$	15,346	$	50,518

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

The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements:


	March 31, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
In thousands, except percentages	Amount		Fair Value		Amount		Fair Value

7¹/2% Senior Subordinated Notes due 2013⁽¹⁾	$	55,352	$	55,448	$	224,563	$	228,375
7¹/2% Senior Subordinated Notes due 2015		-		-		300,427		310,500
9¹/2% Senior Subordinated Notes due 2016		238,826		253,597		239,509		249,661
9³/4% Senior Subordinated Notes due 2016		405,283		480,710		404,211		475,380
8¹/4% Senior Subordinated Notes due 2020		996,273		1,113,335		996,273		1,080,956
6³/8% Senior Subordinated Notes due 2021		400,000		410,000		-		-



(1) These notes were repurchased on April 1, 2011.

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

Note 6. Supplemental Information

Accounts Payable and Accrued Liabilities

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


	March 31,		December 31,
In thousands	2011		2010
Accounts payable	$	53,754	$	47,660
Accrued exploration and development costs		75,967		101,758
Accrued compensation		17,820		39,757
Accrued interest		31,405		57,077
Taxes payable		7,198		34,371
Other		60,001		65,375

Total	$	246,145	$	345,998

Supplemental Cash Flow Information

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


	As of
	March 31,
In thousands	2011		2010
Cash paid for interest, net of amounts capitalized	$	66,172	$	21,962
Interest capitalized		10,957		21,312
Cash paid for income taxes		19,933		8,030
Cash received for income tax refunds		222		12,625
Increase (decrease) in accrued liabilities for capital expenditures		(12,503)		32,399
Issuance of Denbury common stock in connection with the Encore Merger		-		2,085,681

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 7. Commitments and Contingencies

In March 2011, we entered into three long-term supply contracts to purchase CO₂ from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. Denbury will purchase 100% of the CO₂ captured from the DKRW Advanced Fuels LLC’s Medicine Bow Fuel and Power LLC (“MBFP”) project in Medicine Bow, Wyoming, purchase 70% of the CO₂ captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and purchase 100% of the CO₂ captured from an undisclosed source in the Gulf Coast region. These contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these sources will supply approximately 365 MMcf/d of CO₂ for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 200 MMCF/d of CO₂ from the MBFP project in late 2014 or early 2015, 115 MMcf/d of CO₂ from the IGCC project by 2014 and 50 MMcf/d of CO₂ from a Gulf Coast region source in late 2012. Our aggregate maximum purchase obligation for CO₂ purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO₂ will fluctuate based on the changes in the price of oil. These CO₂purchase agreements are contingent on completion or modification of the respective plants by their operators.

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

We are subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. We have received a $15.0 million assessment from the Mississippi taxing authority for use tax, penalties and interest covering the 2004-2007 period. We believe this assessment is significantly in excess of any amounts owed and we are appealing the assessment. We do not believe the outcome of this matter will have a material adverse impact on the Company.

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.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. Condensed Consolidating Financial Information

Denbury’s subordinated debt is fully and unconditionally guaranteed jointly and severally by certain of its subsidiaries, except that with respect to Denbury’s $55 million of 7½% Senior Subordinated Notes due 2013 that remained outstanding at March 31, 2011, Denbury Resources Inc. and Denbury Onshore, LLC were co-obligors at March 31, 2011. These 7½% Notes have since been redeemed and are no longer outstanding. Except as noted in the first sentence of this paragraph, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. In the case of the 6¼% Notes, the 6% Notes, the 7¼% Notes and the 9½% Notes previously issued by Encore, Denbury is the sole issuer by virtue of the fact that it is the successor in interest to Encore with respect to all such notes. Each subsidiary guarantor and the subsidiary that was a co-obligor are wholly-owned, directly or indirectly, by Denbury Resources Inc.

All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between Denbury Resources Inc., Denbury Onshore, LLC, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with Denbury Resources Inc. and then eliminated to arrive at consolidated totals per the accompanying Unaudited Condensed Consolidated Financial Statements.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Balance Sheets


	March 31, 2011
	Denbury		Denbury

	Resources Inc.		Onshore, LLC

	(Parent and		(Issuer and		Guarantor		Non-Guarantor				Consolidated

In thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Subsidiaries		Eliminations		Total
ASSETS
Current assets:
Cash and cash equivalents	$	3,947	$	119,569	$	3,630	$	711	$	-	$	127,857
Other current assets		476,986		559,354		461,605		-		(904,139)		593,806

Total current assets		480,933		678,923		465,235		711		(904,139)		721,663


Property and equipment:
Oil and natural gas properties (using full cost accounting):												-
Proved		-		6,238,629		-		-		-		6,238,629
Unevaluated		-		912,267		-		-		-		912,267
CO₂ and other non-hydrocarbon gases - properties and pipelines		-		707,008		1,223,900		9,484		-		1,940,392
Other property and equipment		-		128,421		4,271		-		-		132,692
Less accumulated depletion, depreciation, amortization, and impairment		-		(2,267,862)		(28,090)		-		-		(2,295,952)

Net property and equipment		-		5,718,463		1,200,081		9,484		-		6,928,028


Derivative assets		-		9,203		-		-		-		9,203
Goodwill		1,061,123		171,295		-		-		-		1,232,418
Other assets		549,334		144,456		7		33		(473,723)		220,107
Investment in subsidiaries (equity method)		4,354,965		2,666		4,369,801		-		(8,727,432)		-

Total assets	$	6,446,355	$	6,725,006	$	6,035,124	$	10,228	$	(10,105,294)	$	9,111,419


LIABILITIES AND EQUITY
Current liabilities	$	20,764	$	901,331	$	609,794	$	10,723	$	(904,139)	$	638,473
Long-term debt, net of current portion		2,044,226		726,905		-		-		(426,350)		2,344,781
Asset retirement obligations		-		83,576		-		-		-		83,576
Derivative liabilities		-		47,745		-		-		-		47,745
Deferred taxes		-		569,597		1,067,688		-		(47,373)		1,589,912
Other liabilities		-		22,890		2,677		-		-		25,567

Total liabilities		2,064,990		2,352,044		1,680,159		10,723		(1,377,862)		4,730,054
Total equity		4,381,365		4,372,962		4,354,965		(495)		(8,727,432)		4,381,365

Total liabilities and equity	$	6,446,355	$	6,725,006	$	6,035,124	$	10,228	$	(10,105,294)	$	9,111,419


	December 31, 2010
	Denbury		Denbury

	Resources Inc.		Onshore, LLC

	(Parent and		(Issuer and		Guarantor		Non-Guarantor				Consolidated

In thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Subsidiaries		Eliminations		Total
ASSETS
Current assets:
Cash and cash equivalents	$	457	$	380,273	$	1,139	$	-	$	-	$	381,869
Other current assets		144,247		487,942		449,871		-		(599,611)		482,449

Total current assets		144,704		868,215		451,010		-		(599,611)		864,318


Property and equipment:
Oil and natural gas properties (using full cost accounting):												-
Proved		-		6,042,442		-		-		-		6,042,442
Unevaluated		-		870,130		-		-		-		870,130
CO₂ and other non-hydrocarbon gases - properties and pipelines		-		681,963		1,216,841		2,858		-		1,901,662
Other property and equipment		-		116,370		4,271		-		-		120,641
Less accumulated depletion, depreciation, amortization and impairment		-		(2,177,040)		(20,477)		-		-		(2,197,517)

Net property and equipment		-		5,533,865		1,200,635		2,858		-		6,737,358


Derivative assets		-		12,919		-		-		-		12,919
Goodwill		1,061,123		171,295		-		-		-		1,232,418
Other assets		830,454		144,333		7		-		(756,744)		218,050
Investment in subsidiaries (equity method)		4,332,347		2,666		4,357,128		-		(8,692,141)		-

Total assets	$	6,368,628	$	6,733,293	$	6,008,780	$	2,858	$	(10,048,496)	$	9,065,063


LIABILITIES AND EQUITY
Current liabilities	$	43,654		517,686		614,388		3,228		(599,611)		579,345
Long-term debt, net of current portion		1,944,267		1,198,291		-		-		(726,350)		2,416,208
Asset retirement obligations		-		81,290		-		-		-		81,290
Derivative liabilities		-		29,687		-		-		-		29,687
Deferred taxes		-		516,319		1,062,045		22		(30,394)		1,547,992
Other liabilities		-		29,834		-		-		-		29,834

Total liabilities		1,987,921		2,373,107		1,676,433		3,250		(1,356,355)		4,684,356
Total equity		4,380,707		4,360,186		4,332,347		(392)		(8,692,141)		4,380,707

Total liabilities and equity	$	6,368,628	$	6,733,293	$	6,008,780	$	2,858	$	(10,048,496)	$	9,065,063

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations


	Three Months Ended March 31, 2011
	Denbury		Denbury

	Resources Inc.		Onshore, LLC

	(Parent and		(Issuer and		Guarantor		Non-Guarantor				Consolidated

In thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Subsidiaries		Eliminations		Total

Revenues and other income:
Oil, natural gas, and related product sales	$	-	$	506,192	$	-	$	-	$	-	$	506,192
CO₂ sales and transportation fees		-		3,733		22,217		-		(21,026)		4,924
Interest income and other		32,433		3,047		8,594		-		(41,025)		3,049

Total revenues		32,433		512,972		30,811		-		(62,051)		514,165

Expenses:
Lease operating expenses		-		145,846		-		-		(18,749)		127,097
Production taxes and marketing expenses		-		32,751		-		-		-		32,751
CO₂ discovery and operating expenses		-		1,809		2,622		-		(2,277)		2,154
General and administrative		191		42,553		945		157		-		43,846
Interest, net of amounts capitalized		50,321		12,647		(301)		-		(13,890)		48,777
Depletion, depreciation, and amortization		-		92,212		1,382		-		-		93,594
Derivatives expense		-		170,750		-		-		-		170,750
Loaa on early extinguishment of debt		13,670		2,113		-		-		-		15,783
Transaction costs and other related to the Encore Merger		-		123		2,236		-		-		2,359

Total expenses		64,182		500,804		6,884		157		(34,916)		537,111

Income (loss) before income taxes		(31,749)		12,168		23,927		(157)		(27,135)		(22,946)
Income tax provision (benefit)		(17,661)		3,574		5,386		(55)		-		(8,756)

Consolidated net income (loss)	$	(14,088)	$	8,594	$	18,541	$	(102)	$	(27,135)	$	(14,190)


	Three Months Ended March 31, 2010
	Denbury		Denbury

	Resources Inc.		Onshore, LLC

	(Parent and		(Issuer and		Guarantor		Non-Guarantor				Consolidated

In thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Subsidiaries		Eliminations		Total

Revenues and other income:
Oil, natural gas, and related product sales	$	-	$	270,571	$	47,881	$	12,434	$	-	$	330,886
CO₂ sales and transportation fees		-		4,497		-		-		-		4,497
Gain on sale of interests in Genesis		-		(160)		101,728				-		101,568
Interest income and other		127,106		827		(7,446)		4		(118,621)		1,870

Total revenues		127,106		275,735		142,163		12,438		(118,621)		438,821

Expenses:
Lease operating expenses		-		85,884		7,552		2,784		-		96,220
Production taxes and marketing expenses		-		12,277		5,653		1,387		-		19,317
CO₂ discovery and operating expenses		-		1,360		8		-		-		1,368
General and administrative		118		26,683		5,227		681		-		32,709
Interest, net of amounts capitalized		33,828		13,944		(6,418)		1,079		(16,017)		26,416
Depletion, depreciation, and amortization		-		65,025		13,748		3,099		-		81,872
Derivatives income		-		(31,638)		(5,817)		(3,770)		-		(41,225)
Transaction costs and other related to the Encore Merger				43,809		252		938		-		44,999

Total expenses		33,946		217,344		20,205		6,198		(16,017)		261,676

Income before income taxes		93,160		58,391		121,958		6,240		(102,604)		177,145
Income tax provision (benefit)		(7,044)		66,871		17,101		13		-		76,941

Consolidated net income (loss)		100,204		(8,480)		104,857		6,227		(102,604)		100,204

Less: net income attributable to noncontrolling interest		-		-		-		(3,316)		-		(3,316)

Consolidated net income (loss) attributable to Denbury stockholders	$	100,204	$	(8,480)	$	104,857	$	2,911	$	(102,604)	$	96,888

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Cash Flows


	Three Months Ended March 31, 2011
	Denbury		Denbury

	Resources Inc.		Onshore, LLC

	(Parent and		(Issuer and		Guarantor		Non-Guarantor				Consolidated

In thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Subsidiaries		Eliminations		Total

Cash flow from operating activities:
Net cash provided by (used for) operating activities	$	(74,995)	$	476,567	$	30,785	$	5,549	$	(313,074)	$	124,832

Cash flow used for investing activities:
Oil and natural gas capital expenditures		-		(190,296)		-		-		-		(190,296)
Acquisitions of oil and natural gas properties		-		(29,801)		-		-		-		(29,801)
CO₂ and other non-hydrocarbon gases - capital expenditures, including pipelines		-		(33,025)		(28,294)		(4,838)		-		(66,157)
Other		-		1,211		-		-		-		1,211

Net cash used for investing activities		-		(251,911)		(28,294)		(4,838)		-		(285,043)

Cash flow from financing activities:
Bank repayments		(130,000)		-		-		-		-		(130,000)
Bank borrowings		130,000		-		-		-		-		130,000
Repayment of senior subordinated notes		(300,000)		(469,552)		-		-		300,000		(469,552)
Premium paid on repayment of senior subordinated notes		(12,078)		(13,137)		-		-		12,078		(13,137)
Net proceeds from issuance of senior subordinated debt		400,000		-		-		-		-		400,000
Costs of debt financing		(8,441)		-		-		-		-		(8,441)
Other		(996)		(2,671)		-		-		996		(2,671)

Net cash provided by (used for) financing activities		78,485		(485,360)		-		-		313,074		(93,801)

Net increase (decrease) in cash and cash equivalents		3,490		(260,704)		2,491		711		-		(254,012)
Cash and cash equivalents at beginning of period		457		380,273		1,139		-		-		381,869

Cash and cash equivalents at end of period	$	3,947	$	119,569	$	3,630	$	711	$	-	$	127,857


	Three Months Ended March 31, 2010
	Denbury		Denbury

	Resources Inc.		Onshore, LLC

	(Parent and		(Issuer and		Guarantor		Non-Guarantor				Consolidated

In thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Subsidiaries		Eliminations		Total

Cash flow from operating activities:
Net cash provided by operating activities	$	3,173	$	219,573	$	190,852	$	6,882	$	(307,312)	$	113,168

Cash flow used for investing activities:
Oil and natural gas capital expenditures		-		(70,061)		(22,262)		(324)		-		(92,647)
Acquisitions of oil and natural gas properties		-		(503)		455		(292)		-		(340)
Cash paid in Encore Merger, net of cash acquired		(830,310)		-		15,705		13,116		-		(801,489)
CO₂ and other non-hydrocarbon gases - capital expenditures, including pipelines		-		(37,011)		(35,636)		-		-		(72,647)
Deposit received on divesture of Southern Assets		45,000		-		-		-		-		45,000
Net proceeds from sales of oil and gas properties and equipment		-		23,537		139,085		-		-		162,622
Investments in subsidiaries (equity method)		(305,646)		-		-		-		305,646		-
Other		-		(4,799)		(27)		-		-		(4,826)

Net cash provided by (used for) investing activities		(1,090,956)		(88,837)		97,320		12,500		305,646		(764,327)

Cash flow from financing activities:
Bank repayments		-		(350,000)		(265,000)		(10,000)		-		(625,000)
Bank borrowings		800,000		225,000		-		-		-		1,025,000
Repayment of senior subordinated notes		(508,182)		-		-		-		-		(508,182)
Premium paid on repayment of senior subordinated notes		(6,257)										(6,257)
Net proceeds from issuance of senior subordinated debt		1,000,000		-		-		-		-		1,000,000
Escrowed Funds for senior subordinated notes redemption		(65,566)		-		-		-		-		(65,566)
Costs of debt financing		(76,129)		-		-		-		-		(76,129)
Other		(1,666)		(2,139)		(1,974)		-		1,666		(4,113)

Net cash provided by (used for) financing activities		1,142,200		(127,139)		(266,974)		(10,000)		1,666		739,753

Net increase in cash and cash equivalents		54,417		3,597		21,198		9,382		-		88,594
Cash and cash equivalents at beginning of period		24		20,281		286		-		-		20,591

Cash and cash equivalents at end of period	$	54,441	$	23,878	$	21,484	$	9,382	$	-	$	109,185

Note 9. Subsequent Events

Redemption of our 2013 Notes

On February 3, 2011, we commenced cash tender offers to purchase $225 million principal amount of our 2013 Notes. By March 3, 2011, upon expiration of the tender offers, we accepted for purchase $169.6 million in principal amount of the 2013 Notes at 100.625% of par. On April 1, 2011, we repurchased all $55.4 million of our 2013 Notes remaining outstanding at par in accordance with the terms of our indenture. See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for more information.

DENBURY RESOURCES INC.

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

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

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

Overview

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

Operating Highlights. The acquisition of Encore Acquisition Company (the “Encore Merger”) on March 9, 2010, has had a significant impact on nearly every aspect of our business, including oil and natural gas production, revenues and operating expenses. Accordingly, the Encore Merger impacts the comparability of our first quarter 2010 financial results to those in the first quarter of 2011, which is more fully discussed throughout the following discussion and analysis. Our first quarter 2010 financial results include the results of operations for Encore from the date of the acquisition on March 9, 2010 through March 31, 2010. Additionally, throughout 2010 we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).

We recognized a net loss of $14.2 million, or $0.04 per basic common share, during the first quarter of 2011 as compared to net income of $96.9 million, or $0.33 per basic common share, during the first quarter of 2010. This decrease between the two periods is primarily attributable to (1) non-cash fair value losses for our commodity derivatives of $172.3 million in the first quarter of 2011 compared to gains of $100.8 million in 2010, resulting in a $273.1 million negative change between the comparable quarters ($169.3 million after tax), (2) a $101.6 million gain on the sale of Genesis in the first quarter of 2010 ($63.0 million after tax), and (3) a $15.8 million loss in the first quarter of 2011 associated with repurchases of senior subordinated notes ($9.8 million after tax). Partially offsetting these decreases was an increase in oil and gas revenues of $175.3 million due to increased volumes attributable to a full quarter of production from the properties retained from the Encore Merger (versus 22 days of production in the first quarter of 2010), increased tertiary production, and higher oil prices. In-line with higher production volumes, our operating expenses increased across the board. Interest expense also increased significantly due to our additional debt incurred in conjunction with the Encore Merger.

During the first quarter of 2011, our oil and natural gas production averaged 63,604 BOE/d compared to 53,125 BOE/d produced during the first quarter of 2010. This 10,479 BOE/d of additional production is primarily attributable to (1) incremental average production of 14,400 BOE/d from Rocky Mountain region properties acquired in the Encore Merger, and (2) increased tertiary production between the two quarters, offset by (3) a decrease of 6,750 BOE/d due to the sales of non-strategic Encore assets and our interests in ENP after the first quarter of 2010. See Results of Operations — Operating Results — Production for more information.

Tertiary oil production averaged 30,825 Bbls/d during the first quarter of 2011, representing a 14% increase over our average tertiary oil production of 27,023 Bbls/d during the first quarter of 2010. However, tertiary oil production was down slightly from the 31,139 Bbls/d produced during the fourth quarter of 2010. See Results of Operations — CO₂ Operations for more information.

Oil prices during the first quarter of 2011 were considerably higher than prices during the first quarter of 2010. Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $88.42 per BOE during the first quarter of 2011, compared to $69.21 per BOE during the first quarter of 2010, a 28% increase between the two periods. Including the impact of cash settlements on our commodity derivative contracts, our average oil and natural gas price per BOE was $88.70 per BOE during the first quarter of 2011 compared to $56.70 per BOE during the first quarter of 2010.

DENBURY RESOURCES INC.

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

Debt Refinancing. In February 2011, we issued, at par, $400 million of 6³/₈% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to repurchase $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes. Also, in February, we commenced cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. Upon expiration of the tender offers in March 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par and $220.9 million in principal of the 2015 Notes at 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchased all of the remaining outstanding 2015 Notes at 103.75% of par on March 21, 2011 and repurchased all of the remaining outstanding 2013 Notes at par on April 1, 2011. During the first quarter of 2011, we recognized a $15.8 million loss associated with the debt repurchases, included in our income statement under the caption “Loss on early extinguishment of debt”.

CO₂Purchase Contracts. In March 2011, we entered into three long-term supply contracts to purchase CO₂ from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. Denbury will purchase 100% of the CO₂ captured from the DKRW Advanced Fuels LLC’s Medicine Bow Fuel and Power LLC (“MBFP”) project in Medicine Bow, Wyoming, purchase 70% of the CO₂ captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and purchase 100% of the CO₂ captured from an undisclosed source in the Gulf Coast region. We estimate that these sources will supply approximately 365 MMcf/d of CO₂ for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 200 MMCF/d of CO₂ from the MBFP project in late 2014 or early 2015, 115 MMcf/d of CO₂ from the IGCC project by 2014, and 50 MMcf/d of CO₂ from a Gulf Coast region source in late 2012. Our aggregate maximum purchase obligation for CO₂ purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO₂ will fluctuate based on the changes in the price of oil. These CO₂purchase agreements are contingent on completion or modification of the respective plants by their operators.

Capital Resources and Liquidity

In March 2011, commensurate with higher oil prices, our Board of Directors approved an increase in our 2011 capital spending budget, from $1.1 billion to $1.3 billion, excluding capitalized interest, tertiary start-up costs, acquisitions and divestitures, and net of equipment leases. Our current 2011 capital budget includes the following:

	•		$450 million allocated for tertiary oil field expenditures;

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

	•		$250 million to be spent on our CO₂ pipelines;

	•		$150 million to be spent on CO₂sources in the Jackson Dome and Riley Ridge areas; and

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

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

Based on oil and natural gas commodity futures prices in early May 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is $100 million to $200 million greater than our anticipated cash flow from operations. These expenditures will be funded with our excess cash on hand or, if necessary, borrowings under our $1.6 billion Bank Credit Agreement which currently has no outstanding borrowings.

DENBURY RESOURCES INC.

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

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 2011, we have contracted for certain capital expenditures, including construction of the Greencore pipeline, processing facilities at Riley Ridge, and several drilling rigs, and 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 our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding these commitments). See CO₂ Purchase Contracts above and Off-Balance Sheet Arrangements below for further information regarding additional commitments entered into in 2011. We believe that our $1.6 billion Bank Credit Agreement and oil derivative contracts, which provide a $70 floor price through mid-2012 and an $80 floor price for the second half of 2012 on approximately 80%-85% of our currently anticipated proved oil production, provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly.

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


	Three Months Ended
	March 31,
In thousands	2011		2010
Oil and natural gas exploration and development:
Drilling	$	91,732	$	48,261
Geological, geophysical, and acreage		6,666		6,994
Facilities		51,814		37,710
Recompletions		47,402		28,536
Capitalized interest		7,700		5,743

Total oil and natural gas exploration and development expenditures		205,314		127,244
CO₂ and other non-hydrocarbon gases - capital expenditures:
Pipelines and facilities		24,737		42,973
Acreage, geological and drilling		10,615		11,907
Capitalized interest		3,257		15,569

Total CO₂ and other non-hydrocarbon gases capital expenditures		38,609		70,449

Total capital expenditures excluding acquisitions		243,923		197,693

Oil and natural gas property acquisitions		29,801		340
Consideration for Encore Merger⁽¹⁾		-		2,952,515

Total	$	273,724	$	3,150,548


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

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. Our capital expenditures for the first three months of 2010, excluding the Encore Merger, were funded with $113.2 million of cash flow from operations and proceeds from the sale of our interests in Genesis.

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.

DENBURY RESOURCES INC.

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

In April 2011, we entered into three long-term drilling contracts. Our total commitment under these contracts is approximately $55.8 million, with $5.2 million expected to be paid in 2011, $18.6 million in both 2012 and 2013, and $13.4 million in 2014.

Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the section entitled Off-Balance Sheet Arrangements – Commitments and Obligations contained in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding our commitments and obligations. Also see Overview – CO₂Purchase Contracts for discussion of additional purchase contracts we entered into during the first quarter of 2011.

Results of Operations

CO₂ Operations

Our focus on CO₂operations is the primary strategy of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO₂, and we have outlined certain of this potential in our Annual Report on Form 10-K for the year ended December 31, 2010 and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the section entitled CO₂ Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding these matters.

During the first quarter of 2011, our CO₂ production at Jackson Dome averaged 1,021 MMcf/d as compared to an average of 802 MMcf/d produced during the first quarter of 2010 and 974 MMcf/d produced during the fourth quarter of 2010. We used 91% of this production, or 926 MMcf/d, in our tertiary operations during the first quarter of 2011, and sold the balance to our industrial customers, or to Genesis pursuant to our volumetric production payments. Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Off-Balance Sheet Arrangements – Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion on our CO₂ delivery obligations.

We spent approximately $0.25 per Mcf in operating expenses to produce our CO₂ during the first three months of 2011, which is up significantly from our $0.20 per Mcf cost during the first three months of 2010, due primarily to increased CO₂ royalty expense as a result of higher oil prices (to which CO₂ royalties are tied).

DENBURY RESOURCES INC.

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

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


	Average Daily Production (Bbls/d)
	First		Second		Third		Fourth		First
	Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2010		2010		2010		2010		2011

Phase 1:
Brookhaven		3,416		3,277		3,323		3,699		3,664
McComb area		2,289		2,160		2,484		2,433		2,161
Mallalieu area		3,443		3,628		3,279		3,164		2,925
Other		2,817		3,282		3,343		3,361		3,290
Phase 2:
Heidelberg		1,708		1,857		2,806		3,422		3,374
Eucutta		3,792		3,625		3,284		3,286		3,247
Soso		3,213		3,207		3,016		2,828		2,582
Martinville		927		764		606		586		500
Phase 3:
Tinsley		4,419		5,248		6,024		6,614		6,567
Phase 4:
Cranfield		936		811		855		1,043		991
Phase 5:
Delhi		63		648		511		703		1,524

Total tertiary oil production		27,023		28,507		29,531		31,139		30,825


Tertiary operating expense per Bbl	$	22.67	$	21.37	$	22.54	$	22.26	$	25.40

Oil production from our tertiary operations increased to an average of 30,825 Bbls/d during the first quarter of 2011, a 14% increase over our first quarter of 2010 tertiary production level of 27,023 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods in the Tinsley, Heidelberg and Delhi Fields. Offsetting these production gains were declines in our Mallalieu, Soso, and Eucutta Fields, production from which has most likely peaked and will likely continue to decline in the future.

The production growth rate at a tertiary flood varies from quarter to quarter as a tertiary field’s production may increase rapidly when wells respond to the CO₂, plateau temporarily, and then resume its growth as additional areas of the field are developed. During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production. We also find it difficult to precisely predict when any given well will respond to the injected CO₂ as the CO₂ seldom travels through the rock consistently due to lack of heterogeneity in the oil bearing formations. We find all these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the entire field is developed, albeit sometimes in inconsistent patterns. These types of fluctuations were most noticeable at Tinsley and Heidelberg Fields in the first quarter of 2011, two of our fields which have exhibited strong production growth in recent periods. We expect our tertiary production to resume its growth later this year, as these temporary fluctuations have not changed our overall outlook for these fields.

With the Green Pipeline complete, we initiated CO₂ injections at Oyster Bayou and Hastings Fields during June 2010 and December 2010, respectively. We currently anticipate tertiary production responses at Hastings Field in late 2011 or early 2012, depending on the date of completion of our CO₂ recycle facilities at this field. We anticipate first production at Oyster Bayou Field late in the first quarter of 2012, also dependant on the completion of CO₂ recycle facilities. We received the regulatory approvals required to commence construction of the CO₂ recycling facilities at Hastings and Oyster Bayou Fields in the fourth quarter of 2010, after extensive unforeseen regulatory delays, and began construction of these facilities in the first quarter of 2011.

DENBURY RESOURCES INC.

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

During the first quarter of 2011, operating costs for our tertiary properties averaged $25.40 per Bbl, compared to our first quarter of 2010 average cost of $22.67 per Bbl and a fourth quarter of 2010 average of $22.26 per Bbl. The per Bbl increase quarter to quarter was primarily due to increases in utilities, CO₂costs (which are variable and partially tied to oil prices), and workover expenses. On a per Bbl basis, our cost of CO₂ increased by $0.69 per Bbl, from $4.89 per Bbl during the first quarter of 2010 to $5.58 per Bbl during the first quarter of 2011 and increased $0.03 from $5.55 per Bbl during the fourth quarter of 2010 due to slightly lower CO₂injection levels at our tertiary producing fields. First quarter of 2011 workover expenses increased $1.32 per Bbl over the first quarter of 2010 levels and $1.39 per Bbl over fourth quarter of 2010 levels as we accelerated planned mechanical integrity test repairs at Brookhaven Field rather than performing the work throughout the year as originally planned. For any specific field, we expect our tertiary lease operating expense per Bbl to be high initially and then decrease as production increases, ultimately leveling off until production begins to decline in the latter life of the field, when lease operating expense per Bbl will again increase.

Operating Results

Certain of our operating results and statistics for the first three months of 2011 and 2010 are included in the following table:


	Three Months Ended
	March 31,
In thousands, except per share and unit data	2011			2010 ⁽¹⁾

Operating results:
Net income (loss) attributable to Denbury stockholders	$	(14,190	)	$	96,888
Net income (loss) per common share - basic		(0.04	)		0.33
Net income (loss) per common share - diluted		(0.04	)		0.32
Cash flow from operations		124,832			113,168
Average daily production volumes:
Bbls/d		58,460			44,309
Mcf/d		30,866			52,892
BOE/d		63,604			53,125
Operating revenues:
Oil sales	$	492,838		$	305,204
Natural gas sales		13,354			25,682

Total oil and natural gas sales	$	506,192		$	330,886

Commodity derivative contracts:⁽²⁾
Net cash receipts (payments) on settlement of commodity derivative contracts	$	1,588		$	(59,801	)
Non-cash fair value adjustment income (expense)		(172,338	)		100,839

Total income (expense) from commodity derivative contracts	$	(170,750	)	$	41,038

Operating expenses:
Lease operating	$	127,097		$	96,220
Production taxes and marketing		32,751			19,317

Total production expenses	$	159,848		$	115,537

Unit prices - including impact of derivative settlements:⁽²⁾
Oil price per Bbl	$	92.72		$	60.60
Natural gas price per Mcf		7.19			6.18
Unit prices - excluding impact of derivative settlements:⁽²⁾
Oil price per Bbl	$	93.67		$	76.53
Natural gas price per Mcf		4.81			5.40
Oil and natural gas operating revenues and expenses per BOE:
Oil and natural gas revenues	$	88.42		$	69.21


Oil and natural gas lease operating expenses	$	22.20		$	20.12
Oil and natural gas production taxes and marketing expense		5.72			4.04

Total oil and natural gas production expenses	$	27.92		$	24.16


(1)		Includes the results of operations of Encore properties and ENP from March 9, 2010 through March 31, 2010.

(2)		See Item 3, Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts.

DENBURY RESOURCES INC.

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

Production. Average daily production by area for each of the four quarters of 2010 and for the first quarter of 2011 are shown below:


	Average Daily Production (BOE/d)
	First		Pro Forma		Second		Third		Fourth		First
	Quarter		First Quarter		Quarter		Quarter		Quarter		Quarter
Operating Area	2010 ⁽¹⁾		2010 ⁽²⁾		2010		2010		2010		2011

Gulf Coast Region:
Tertiary oil fields		27,023		27,023		28,507		29,531		31,139		30,825
Non-tertiary fields:
Mississippi		7,829		7,829		8,967		7,965		7,293		7,586
Texas		5,235		5,235		5,148		4,824		4,564		4,371
Louisiana		662		662		775		714		687		767
Alabama and other		997		997		1,078		1,091		1,026		1,026

Total Gulf Coast Region		41,746		41,746		44,475		44,125		44,709		44,575

Rocky Mountain Region:
Cedar Creek Anticline		2,537		9,830		9,967		9,791		9,328		9,163
Bakken		890		3,549		4,500		4,657		5,193		5,728
Bell Creek		252		966		997		994		957		890
Paradox		173		675		702		738		716		635
Other		777		2,925		2,944		2,889		2,809		2,613

Total Rocky Mountain Region		4,629		17,945		19,110		19,069		19,003		19,029


Total Continuing Production		46,375		59,691		63,585		63,194		63,712		63,604


Disposed Properties:
Legacy Encore properties		4,479		17,853		11,684		5,906		4,156		-
ENP		2,271		9,034		8,842		8,630		8,567		-

Total Production		53,125		86,578		84,111		77,730		76,435		63,604

	(1)		Includes production of Encore and ENP from March 9, 2010 through March 31, 2010.

	(2)		Represents pro forma production assuming we had reported the production from the Encore Merger beginning January 1, 2010.

As outlined in the above table, continuing production during the three months ended March 31, 2011 increased 7% over first quarter 2010 pro forma production levels. These increases were primarily due to the additional production from a 14% increase in our tertiary production and a 61% increase in production from the Bakken, partially offset by normal declines in most of our other properties or declines resulting from a conversion of a portion of the field to a tertiary flood. Additionally, our production from the Cedar Creek Anticline generally declines in periods of increasing prices due to a net profits interest associated with this production.

Production from our Bakken properties averaged 5,728 BOE/d in the first quarter, a 61% increase from first quarter 2010 pro forma production levels and an increase of over 10% as compared to fourth quarter 2010 production levels. The production increases in the Bakken are due to a gradual acceleration of our drilling activities in the area, as we have increased our operated drilling rigs from two, at the time of the Encore acquisition in March 2010, to five operated rigs. We anticipate adding a sixth rig in the third quarter of 2011 to test our acreage in the Almond area, and will likely add a seventh rig by the end of 2011. Our first quarter 2011 Bakken production was negatively impacted by severe winter weather which caused delays in well completions.

DENBURY RESOURCES INC.

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

Our production during the three months ended March 31, 2011 was 92% oil as compared to 83% during the three months ended March 31, 2010. This increase is due to the sales of the non-strategic Encore properties and ENP properties in the second half of 2010, which had a higher percentage of natural gas production.

Oil and Natural Gas Revenues. Due to the significant increase in oil prices between the first three months of 2010 and 2011, our oil and natural gas revenues increased sharply during the first quarter of 2011 as compared to revenues in the first quarter of 2010. 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,
	2011 vs. 2010
			Percentage
	Increase in		Increase in
In thousands	Revenues		Revenues

Change in oil and natural gas revenues due to:
Increase in commodity prices	$	110,042		33	%
Increase in production		65,264		20	%

Total increase in oil and natural gas revenues	$	175,306		53	%

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


	Three Months Ended
	March 31,
	2011			2010

Net Realized Prices:
Oil price per Bbl	$	93.67		$	76.53
Natural gas price per Mcf		4.81			5.40
Price per BOE		88.42			69.21

NYMEX Differentials:
Oil per Bbl	$	(0.59	)	$	(2.08	)
Natural gas per Mcf		0.61			0.37

Our oil NYMEX differential improved during the three months ended March 31, 2011 as compared to our differential in the comparable period of 2010, primarily due to the favorable differential for crude oil sold under Light Louisiana Sweet (“LLS”) index prices, which are the sales prices for approximately 40% of our oil production. During the latter part of the first quarter, the LLS index price increased significantly more than increases in the NYMEX West Texas Intermediate crude oil price, trading as high as $20 over NYMEX. For the first quarter of 2011 this LLS-to-NYMEX differential averaged a positive $9.52 per barrel on a trade-month basis, as compared to a $4.07 differential in the fourth quarter of 2010 and a more typical $2.06 in the first quarter of 2010. While this differential is a significant portion of the pricing formula for approximately 40% of our oil production, other factors may prevent us from realizing the full differential. It is uncertain how long this LLS-to-NYMEX differential will remain at this level. Our oil price differential in the first quarter of 2010 was $2.08 per Bbl below NYMEX, which reflected only a partial period for the acquired Encore properties, which typically receive lower oil prices than our legacy production.

DENBURY RESOURCES INC.

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

Commodity Derivative Contracts. The following tables summarize the impact that our commodity derivative contracts had on our operating results for the three months ended March 31, 2011 and 2010:


	Three Months Ended March 31,
	2011			2010			2011			2010		2011			2010
	Oil						Natural Gas					Total Commodity
In thousands	Derivative Contracts						Derivative Contracts					Derivative Contracts

Non-cash fair value gain (loss)	$	(167,064	)	$	61,821		$	(5,274	)	$	39,018	$	(172,338	)	$	100,839
Cash settlement receipts (payments)		(5,028	)		(63,550	)		6,616			3,749		1,588			(59,801	)

Total	$	(172,092	)	$	(1,729	)	$	1,342		$	42,767	$	(170,750	)	$	41,038

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

Production Expenses. Our lease operating expenses increased approximately 32% between the three months ended March 31, 2011 and 2010 primarily as a result of:

	•		the completion of the Encore Merger on March 9, 2010;

	•		our increasing emphasis on tertiary operations and additional tertiary fields moving into the productive phase (see discussion of those expenses under CO₂ Operations);

	•		higher CO₂costs, primarily due to increasing oil prices (see discussion of those expenses under CO₂ Operations);

	•		increasing personnel and related costs resulting primarily from the Encore Merger; and

	•		increased workover costs primarily in our CO₂operations (see discussion of those expenses under CO₂ Operations).

Lease operating expense per BOE averaged $22.20 per BOE for the three months ended March 31, 2011, as compared to $20.12 per BOE for the same period in 2010. Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $25.40 per BOE during the three months ended March 31, 2011, compared to $22.67 per BOE for the same period in 2010. See CO₂ Operations for a more detailed discussion.

Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes, and as such, increased 70% during the three months ended March 31, 2011, as compared to the same period in 2010. This compares to an increase in oil and natural gas revenues of 53% during the three months ended March 31, 2011. The addition of properties in other operating areas acquired in the Encore Merger also affected these costs. Transportation and plant processing fees increased approximately $1.4 million during the three months ended March 31, 2011 and 2010, primarily due to the addition of properties in other operating areas acquired in the Encore Merger.

General and Administrative Expenses

General and administrative (“G&A”) expenses increased on both a gross and per BOE basis between the three months ended March 31, 2011 and 2010 as set forth below:


	Three Months Ended
	March 31,
In thousands, except per BOE data and employees	2011			2010

Gross cash G&A expense	$	67,697		$	48,274
Gross stock-based compensation		11,337			9,939
State franchise taxes		1,159			1,070
Operator labor and overhead recovery charges		(29,716	)		(22,045	)
Capitalized exploration and development costs		(6,631	)		(4,529	)

Net G&A expense	$	43,846		$	32,709

G&A per BOE:
Net cash G&A expense	$	5.86		$	4.84
Net stock-based compensation		1.60			1.78
State franchise taxes		0.20			0.22

Net G&A expense	$	7.66		$	6.84

Employees as of March 31		1,182			1,251

DENBURY RESOURCES INC.

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

Gross cash G&A expenses increased $19.4 million (40%) during the three months ended March 31, 2011, as compared to the same period of 2010, primarily due to the Encore Merger which closed March 9, 2010. The number of employees at March 31, 2011 compared to March 31, 2010 decreased by 6%, as many Encore employees who did not accept permanent positions with Denbury completed their pre-defined transition period in early 2011. However, compensation and personnel costs were less for the three months ended March 31, 2010, as the compensation and personnel costs for Encore employees were included in our G&A expenses beginning March 9, 2010, the date of the Encore Merger. Prior to the Encore Merger on March 9, 2010, our headcount was 856 employees. The largest increases were related to personnel costs, including salaries, payroll taxes and our 401(k) match. Wage increases also contributed to the increase in G&A, as we consider this necessary in order to remain competitive in our industry.

Additional expense attributable to the legacy Encore office leases and the new Denbury headquarters lease, together with related moving costs, contributed to the higher cash G&A expense during the first quarter of 2011. Additionally, stock-based compensation expense increased $1.4 million when compared to levels in the same period of 2010, due primarily to the effect of Encore’s employees being included for a full quarter in 2011 versus only 22 days during the first quarter of 2010.

The increase in gross G&A expense during the three months ended March 31, 2011, as compared to those costs in the same period of 2010, was offset in part by an increase in operator overhead recovery charges. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year, and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 35% during the three months ended March 31, 2011, as compared to the same period in 2010. Capitalized exploration and development costs also increased between the periods, primarily due to increased compensation costs.

The net effect of these changes resulted in a 34% increase (a 12% increase on a per BOE basis) in G&A expense between the comparable first quarters of 2011 and 2010.

Interest and Financing Expenses


	Three Months Ended
	March 31,
In thousands, except per BOE data and interest rates	2011			2010

Cash interest expense	$	54,206		$	44,974
Non-cash interest expense		5,528			2,754
Less: capitalized interest		(10,957	)		(21,312	)

Interest expense	$	48,777		$	26,416

Interest income and other	$	(3,049	)	$	1,870
Net cash interest expense and other income per BOE ⁽¹⁾	$	7.10		$	4.67
Average debt outstanding	$	2,514,621		$	2,225,700
Average interest rate ⁽²⁾		8.3	%		8.1	%


(1)	Cash interest expense less capitalized interest less interest income and other income on a per BOE basis.

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

Interest expense increased $22.4 million during the three months ended March 31, 2011, as compared to the same period in 2010, primarily due to the increase in our average debt outstanding to finance the Encore Merger which closed in March 2010, a portion of which was repaid during 2010 with proceeds from the sale of non-strategic legacy Encore assets and our ENP ownership interest. The increase in interest expense between the comparative three month periods was also attributable to a 49% decrease in our capitalized interest relating primarily to the Green Pipeline, which was completed and placed into service during the second half of 2010.

DENBURY RESOURCES INC.

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


Depletion, Depreciation, and Amortization
	Three Months Ended
	March 31,
In thousands, except per BOE data	2011		2010
Depletion, depreciation, and amortization (“DD&A”) of oil and natural gas properties	$	82,086	$	71,197
Depletion and depreciation of CO₂ assets		4,590		5,300
Asset retirement obligations		1,563		1,107
Depreciation of other fixed assets		5,355		4,268

Total DD&A	$	93,594	$	81,872


DD&A per BOE:
Oil and natural gas properties	$	14.61	$	15.12
CO₂ assets and other fixed assets		1.74		2.00

Total DD&A cost per BOE	$	16.35	$	17.12

Depletion of oil and natural gas properties increased on an absolute dollars basis during the three months ended March 31, 2011 as compared to the same period of 2010, primarily due to the Encore Merger. However, on a per BOE basis, our DD&A expense decreased from quarter-to-quarter due to incremental production attributable to the properties acquired from Encore, the acquisition of Riley Ridge, and higher tertiary production in the first quarter of 2011.

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

Our DD&A expense for our CO₂ assets decreased on an absolute basis for the three months ended March 31, 2011 compared to the prior periods due to proved CO₂ reserve increases at Jackson Dome and Riley Ridge at the end of 2010. On a per BOE basis, DD&A expense for our CO₂ assets and other fixed assets decreased for the three months ended March 31, 2011 compared to those in the prior year quarter due to increased oil and natural gas production volumes as a result of the Encore Merger, which closed in March 2010, and as a result of proved CO₂ reserve additions noted above.

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, 2011. However, if oil and natural gas prices were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost pool ceiling test in the future. The possibility and amount of any future write-down is difficult to predict, and will depend upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures, and additional capital spent.

Encore Transaction and Other Costs

FASC Business Combinations topic requires that all transaction-related costs (advisory, legal, accounting, due diligence, integration, etc.) be expensed as incurred. We recognized transaction and other costs of $2.4 million and $45.0 million for the three months ended March 31, 2011 and 2010, respectively, associated with the Encore Merger, including $1.8 million and $1.2 million, respectively, related to severance costs. We anticipate that these severance costs will decline in the remainder of 2011 as the integration winds down and fewer former Encore transition employees remain.

DENBURY RESOURCES INC.

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


Income Taxes
	Three Months Ended
	March 31,
In thousands, except per BOE amounts and tax rates	2011		2010
Current income tax provision (benefit)	$	(848)	$	669
Deferred income tax provision (benefit)		(7,908)		76,272

Total income tax provision (benefit)	$	(8,756)	$	76,941

Average income tax provision per BOE	$	(1.53)	$	16.09
Effective tax rate		38.2%		43.4%

Our income taxes are based on an estimated statutory rate of approximately 38%. Our effective tax rate for the first quarter of 2011 was slightly higher compared to our statutory rate, primarily due to nondeductible compensation. Our effective tax rate for the comparative quarter was higher than the historical statutory rate due to the remeasurement of our deferred tax liabilities as a result of the Encore Merger in the first quarter of 2010 that resulted in an additional income tax provision of approximately $10 million. During the three months ended March 31, 2010, the current income tax expense represented our state income taxes, primarily related to the sale of our interest in Genesis.

As of March 31, 2011, we had an estimated $39.8 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.5 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2011 or future years. The enhanced oil recovery credits do not begin to expire until 2024. Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.

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

The current administration in Washington D.C. is attempting to remove many tax incentives for the oil and gas industry. Those items that would have the most significant impact on us would include the loss of the domestic manufacturing deduction as well as the repeal of the immediate expensing of intangible drilling costs and tertiary injectant costs. It is uncertain whether or not the current administration will be successful in changing the laws, but if they were successful, it would likely increase the amount of cash taxes that we pay. Should cash taxes increase significantly, it could impact our forecasted 2011 capital expenditure budget.

DENBURY RESOURCES INC.

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

Per BOE Data

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


	Three Months Ended
	March 31,
Per BOE data	2011			2010
Oil and natural gas revenues	$	88.42		$	69.21
Gain (loss) on settlements of derivative contracts		0.28			(12.51	)
Lease operating expenses		(22.20	)		(20.12	)
Production taxes and marketing expenses		(5.72	)		(4.04	)

Production netback		60.78			32.54
Non-tertiary CO₂ operating margin		0.48			0.65
General and administrative expenses		(7.66	)		(6.84	)
Transaction and other costs related to the Encore Merger		(0.41	)		(9.41	)
Net cash interest expense and other income		(7.10	)		(4.67	)
Current income taxes and other		1.29			1.53
Changes in assets and liabilities relating to operations		(25.57	)		9.87

Cash flow from operations		21.81			23.67
DD&A		(16.35	)		(17.12	)
Deferred income taxes		1.38			(15.95	)
Gain on sale of interests in Genesis		-			21.24
Loss on early extinguishment of debt		(2.76	)		-
Non-cash fair value derivative adjustments		(30.11	)		21.13
Net income attributable to noncontrolling interest		-			(0.69	)
Changes in assets and liabilities and other non-cash items		23.55			(12.02	)

Net income (loss) attributable to Denbury stockholders	$	(2.48	)	$	20.26

Critical Accounting Policies

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

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 this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, dates of pipeline construction commencement and completion, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, timing of CO₂ injections in tertiary flooding projects, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves, potential reserves from tertiary operations, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and natural gas prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target,” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas; unexpected difficulties in integrating the operations of Denbury and Encore; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets; general economic conditions; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and natural gas drilling and production activities or which are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

DENBURY RESOURCES INC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Long-Term Debt and Interest Rate Sensitivity

We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies. The fair value of the subordinated debt is based on quoted market prices. The following table presents the carrying and fair values of our debt, along with average interest rates at March 31, 2011:


	Expected Maturity Dates														Carrying		Fair
In thousands, except percentages	2013		2014		2015		2016		2017		2020		2021		Value		Value
Variable rate debt:
Bank Credit Agreement	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Fixed rate debt:
7.5% Senior Subordinated Notes due 2013⁽¹⁾		55,448		-		-		-		-		-		-		55,352		55,448
9.5% Senior Subordinated Notes due 2016		-		-		-		224,920		-		-		-		238,826		253,597
9.75% Senior Subordinated Notes due 2016		-		-		-		426,350		-		-		-		405,283		480,710
8.25% Senior Subordinated Notes due 2020		-		-		-		-		-		996,273		-		996,273		1,113,335
6.375% Senior Subordinated Notes due 2021		-		-		-		-		-		-		400,000		400,000		410,000
Other Subordinated Notes		-		1,072		485		-		2,250		-		-		3,845		3,807


(1) These notes were repurchased on April 1, 2011. See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements, for further information.

Commodity Derivative Contracts and Commodity Price Sensitivity

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

All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our bank credit agreement. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

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

At March 31, 2011, our commodity derivative contracts were recorded at their fair value, which was a net liability of approximately $216.3 million (excluding $21.2 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 significant change from the $44.0 million fair value liability recorded at December 31, 2010. This change is primarily related to the oil futures prices as of March 31, 2011 in relation to the commodity derivative contracts for 2011 through 2012.

DENBURY RESOURCES INC.

Based on NYMEX crude oil and natural gas futures prices as of March 31, 2011, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil and natural gas derivative contracts as seen in the following table:


	Crude Oil			Natural Gas
	Derivative			Derivative
	Contracts			Contracts
In thousands	(Payment)			Receipt
In thousands
Based on:
NYMEX futures prices as of March 31, 2011	$	(120,867	)	$	30,033
10% increase in prices		(308,210	)		21,692
10% decrease in prices		(11,555	)		38,358

Equity Price Sensitivity

Our investment in Vanguard common units is considered an investment in available-for-sale securities, which are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. This investment is thus subject to equity price sensitivity, as fair value is determined by quoted market prices. We estimate that a hypothetical 10% increase or decrease in quoted market prices for Vanguard common units would result in a $10.0 million unrealized gain or loss, respectively, as of March 31, 2011.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, the Company’s Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2011 to ensure: that information required to be disclosed in the reports it files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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

DENBURY RESOURCES INC.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the first quarter of 2011, consisting entirely of delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights:


					Total Number of		Approximate Dollar
	Total				Shares Purchased		Value of Shares
	Number of		Average		as Part of Publicly		that May Yet Be
	Shares		Price Paid		Announced Plans or		Purchased Under the
Month	Purchased		per Share		Programs		Plans or Programs
January 2011		84,250	$	19.76		-	$	-
February 2011		36,513		22.46		-		-
March 2011		208,893		24.31		-		-

Total		329,656		22.94		-	$	-

Item 6. Exhibits


Exhibit		Description
10(a)* **		Form of 2011 Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)* **		Form of 2011 Performance Cash Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*		Interactive Data Files.


* Filed herewith.

** Compensation arrangements.

DENBURY RESOURCES INC.

SIGNATURES

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


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


	By:	/s/ Alan Rhoades
		Alan Rhoades
		Vice President and Chief Accounting Officer

Date: May 10, 2011

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