Denbury (DNRWW) 10-Q 2007 Q1 Quarterly report

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, 2007

o Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 1-12935

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.)
5100 Tennyson Parkway Suite 1200 Plano, TX (Address of principal executive offices)	75024 (Zip code)
Registrant’s telephone number, including area code:	(972) 673-2000

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. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. (See definition of “accelerated filer and large accelerated filer” in Rule 12-b2 of the Exchange Act). (Check one):

Large accelerated filerþ           Accelerated filero           Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yeso Noþ

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

Class	Outstanding at April 30, 2007
Common Stock, $.001 par value	121,091,494

INDEX

	Page
Part I. Financial Information
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at March 31, 2007 and December 31, 2006		3
Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2007 and 2006		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2006		5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three Months Ended March 31, 2007 and 2006		6
Notes to Unaudited Condensed Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3. Quantitative and Qualitative Disclosures about Market Risk		30
Item 4. Controls and Procedures		30
Part II. Other Information
Item 1. Legal Proceedings		30
Item 1A. Risk Factors		30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30
Item 3. Defaults Upon Senior Securities		30
Item 4. Submission of Matters to a Vote of Security Holders		30
Item 5. Other Information		30
Item 6. Exhibits		31
Signatures		32
First Amendment to 6th Amended and Restated Credit Agreement
Amendment for Increased Commitment - Restated Credit Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification Pursuant to Section 906

2

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares)

	March 31,			December 31,
	2007			2006
Assets
Current assets
Cash and cash equivalents	$	35,007		$	53,873
Accrued production receivable		70,783			72,279
Related party receivable — Genesis		134			119
Trade and other receivables, net of allowance of $333 and $315		33,292			24,260
Deferred tax asset		5,570			5,855
Derivative assets		—			26,883
Total current assets		144,786			183,269
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		2,340,795			2,226,942
Unevaluated		360,665			293,657
CO2 properties and equipment		299,061			267,483
Other		43,972			43,133
Less accumulated depletion and depreciation		(991,685	)		(951,447	)
Net property and equipment		2,052,808			1,879,768
Investment in Genesis		10,543			10,640
Deposits on property under option or contract		49,035			49,002
Other assets		18,028			17,158
Total assets	$	2,275,200		$	2,139,837
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	132,561		$	139,111
Oil and gas production payable		53,673			52,244
Derivative liabilities		13,279			4,302
Deferred revenue — Genesis		4,070			4,070
Short-term capital lease obligations		686			671
Total current liabilities		204,269			200,398
Long-term liabilities
Capital lease obligations		6,214			6,387
Long-term debt, net of discount		603,834			507,786
Asset retirement obligations		42,479			39,331
Derivative liabilities		6,975			6,834
Deferred revenue — Genesis		27,887			28,843
Deferred tax liability		238,813			235,780
Other		11,638			8,419
Total long-term liabilities		937,840			833,380
Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized; none issued and outstanding		—			—
Common stock, $.001 par value, 250,000,000 shares authorized; 121,275,128 and 120,506,815 shares issued at March 31, 2007 and December 31, 2006, respectively		121			121
Paid-in capital in excess of par		626,094			616,046
Retained earnings		514,648			498,032
Accumulated other comprehensive loss		(513	)		—
Treasury stock, at cost, 330,264 and 370,327 shares at March 31, 2007 and December 31, 2006, respectively		(7,259	)		(8,140	)
Total stockholders’ equity		1,133,091			1,106,059
Total liabilities and stockholders’ equity	$	2,275,200		$	2,139,837

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

3

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended
	March 31,
	2007		2006
Revenues
Oil, natural gas and related product sales:
Unrelated parties	$	169,123	$	174,094
Related party — Genesis		11		1,449
CO2 sales and transportation fees		3,091		1,988
Interest income and other		1,783		1,375
Total revenues		174,008		178,906
Expenses
Lease operating expenses		50,557		36,172
Production taxes and marketing expenses		9,103		6,945
Transportation expense — Genesis		1,101		1,142
CO2 operating expenses		703		645
General and administrative		11,434		9,867
Interest, net of interest capitalized of $4,033 and $274, respectively		6,075		8,254
Depletion, depreciation, and amortization		41,027		32,743
Commodity derivative expense		26,907		11,630
Total expenses		146,907		107,398
Equity in net income of Genesis		147		240
Income before income taxes		27,248		71,748
Income tax provision
Current income taxes		1,618		9,786
Deferred income taxes		9,014		18,184
Net income	$	16,616	$	43,778
Net income per common share — basic	$	0.14	$	0.39
Net income per common share — diluted	$	0.13	$	0.37
Weighted average common shares outstanding
Basic		118,992		113,151
Diluted		123,954		119,925

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

4

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Three Months Ended
	March 31,
	2007			2006
Cash flow from operating activities:
Net income	$	16,616		$	43,778
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization		41,027			32,743
Non-cash derivative adjustments		35,158			10,862
Deferred income taxes		9,014			18,184
Deferred revenue — Genesis		(956	)		(940	)
Stock-based compensation		2,786			2,972
Amortization of debt issue costs and other		582			250
Changes in assets and liabilities relating to operations:
Accrued production receivable		1,480			157
Trade and other receivables		(8,979	)		4,258
Other assets		(22	)		(10,132	)
Accounts payable and accrued liabilities		(4,986	)		(4,741	)
Oil and gas production payable		1,429			4,866
Other liabilities		196			255
Net cash provided by operating activities		93,345			102,512
Cash flow used for investing activities:
Oil and natural gas expenditures		(139,019	)		(118,599	)
Acquisitions of oil and gas properties		(39,137	)		(252,410	)
Change in accrual for capital expenditures		(4,255	)		10,028
Acquisitions of CO2 assets and CO2 capital expenditures		(31,416	)		(11,024	)
Net purchases of other assets		(897	)		(1,940	)
Proceeds from sales of oil and gas properties and equipment		5			—
Deposits on properties under option or contract		(33	)		26,299
Increase in restricted cash		(863	)		(38	)
Net cash used for investing activities		(215,615	)		(347,684	)
Cash flow from financing activities:
Bank borrowings		96,000			100,000
Costs of debt financing		(205	)		(88	)
Payments on capital lease obligations		(161	)		(138	)
Issuance of common stock		5,210			4,465
Income tax benefit from equity awards		2,560			5,835
Purchase of treasury stock		—			(7	)
Net cash provided by financing activities		103,404			110,067
Net decrease in cash and cash equivalents		(18,866	)		(135,105	)
Cash and cash equivalents at beginning of period		53,873			165,089
Cash and cash equivalents at end of period	$	35,007		$	29,984
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	2,379		$	1,125
Cash paid during the period for income taxes		1,038			6

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

5

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF

COMPREHENSIVE OPERATIONS

(In thousands)

	Three Months Ended
	March 31,
	2007			2006
Net income	$	16,616		$	43,778
Other comprehensive loss, net of income tax:
Change in fair value of derivative contracts designated as a hedge, net of tax of $328		(513	)		—
Comprehensive income	$	16,103		$	43,778

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

6

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Interim Financial Statements

     The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Denbury” or “Company” refer to Denbury Resources Inc. and its subsidiaries. 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, 2006. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K.

     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 fiscal year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of March 31, 2007 and the consolidated results of its operations and cash flows for the three month periods ended March 31, 2007 and 2006. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Net Income Per Common Share

     Basic net income per common share is computed by dividing net income 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 on net income and common shares for the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and any other convertible securities outstanding. For the three month periods ended March 31, 2007 and 2006, there were no adjustments to net income for purposes of calculating diluted net income per common share. In April 2006, we issued 3,492,595 shares of common stock in a public offering. 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 three month periods ended March 31, 2007 and 2006.

	Three Months Ended
	March 31,
Share amounts in thousands	2007		2006
Weighted average common shares — basic		118,992		113,151
Potentially dilutive securities:
Stock options and SARs		4,338		5,880
Restricted stock		624		894
Weighted average common shares — diluted		123,954		119,925

     The weighted average common shares — basic amount excludes 1,529,078 shares in 2007 and 2,047,576 shares in 2006 of non-vested restricted stock that is subject to future vesting over time. 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 weighted average common shares — diluted, the non-vested restricted stock is included in the computation using the treasury stock method, with the proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. The dilution impact of these shares on our earnings per share calculation may increase in future periods, depending on the market price of our common stock during those periods.

7

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     For the three months ended March 31, 2007, common stock options to purchase approximately 193,000 shares of common stock were outstanding but excluded from the diluted net income per common share calculation, as the exercise prices of the options exceeded the average market price of the Company’s common stock during this period and would be anti-dilutive to the calculation. There were no anti-dilutive options outstanding for the three months ended March 31, 2006.

Recently Adopted Accounting Pronouncement

Uncertain Tax Positions

     In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation 48 (“FIN 48”),Accounting for Uncertainties in Income Taxes— an interpretation of FASB Statement No. 109,Accounting for Income Taxes. This interpretation addresses how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and required increased disclosures.

     We adopted the provisions of FIN 48 as of January 1, 2007. As a result of the implementation, we determined that approximately $4.0 million of tax benefits previously recognized were considered uncertain tax positions, as the timing of these deductions may not be sustained upon examination by taxing authorities. As such, upon adoption of FIN 48, we recorded income taxes payable of $4.3 million (including $0.3 million in estimated interest) which was offset by a corresponding reduction of the deferred tax liability of $4.1 million for the tax position that we believe will ultimately be sustained. At January 1, 2007 the total amount of unrecognized tax benefits is $4.5 million, exclusive of interest.

     There was no cumulative adjustment made to the opening balance of retained earnings at January 1, 2007. Our uncertain tax positions relate primarily to timing differences and we do not believe any of such uncertain tax positions will materially impact our effective tax rate in future periods. The amount of unrecognized tax benefits did not materially change as of March 31, 2007. We cannot reasonably estimate the potential change in the unrecognized tax benefits that could occur over the next 12 months.

     We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions. We are currently under examination by both the Internal Revenue Service and State authorities. The IRS is examining 2004 while Mississippi is auditing the periods from 1998 through 2000 and from 2001 through 2003. Louisiana is auditing the periods from 2002 through 2004.

     We have not paid any significant interest or penalties associated with our income taxes, but we will classify both interest expense and penalties as part of our income tax expense.

Recently Issued Accounting Pronouncement

Fair Value Option for Financial Assets and Liabilities

     In February 2007, the FASB issued FASB Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities (“FAS 159”).FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value, with the objective of improving financial reporting by giving entities the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of FAS 159 are effective for us beginning January 1, 2008. We have not yet determined what impact, if any, this pronouncement will have on our financial position or results of operations.

8

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Acquisitions

2007 Acquisition

     On March 30, 2007, Denbury completed the acquisition of the Seabreeze Complex, which is composed of two significant fields and four smaller fields, in the general area of Houston, Texas. These fields are currently producing approximately 400 BOE/d and have estimated current conventional proved reserves of approximately 525 MBOE. Two of these fields are future potential CO₂ tertiary flood candidates. Tertiary flooding at these fields is not expected to begin until 2010 or 2011, following completion of the proposed CO₂ pipeline from Louisiana to Hastings Field, near Houston, Texas.

     The preliminary adjusted purchase price is approximately $41.7 million, after adjusting for interim net cash flow between the effective date and closing date of the acquisition, and minor purchase price adjustments. The preliminary purchase price is subject to final adjustment of the estimated interim net cash flow and potentially other minor adjustments as outlined in the purchase and sales agreement. The preliminary purchase price was allocated between proved and unevaluated oil and natural gas properties based on a risk adjusted analysis of the total estimated value of the proved and probable reserves acquired. Based on this analysis, $5.5 million was assigned to proved properties and $36.1 million was assigned to unevaluated properties. The unevaluated costs are currently excluded from the amortization base and will be transferred to the amortization base as we develop and test the tertiary recovery projects planned in these fields.

     We have not presented any pro forma information for the acquired properties as the pro forma effect was not material to our results of operations for the first quarters of 2007 or 2006.

2006 Acquisition

     On January 31, 2006, we completed an acquisition of three producing oil properties that are future potential CO₂ tertiary oil flood candidates: Tinsley Field approximately 40 miles northwest of Jackson, Mississippi; Citronelle Field in Southwest Alabama, and the smaller South Cypress Creek Field near the Company’s Eucutta Field in Eastern Mississippi. The adjusted purchase price was approximately $250 million (including the $25 million deposited as earnest money as of December 31, 2005), of which $124 million was assigned to unevaluated properties.

Note 3. Asset Retirement Obligations

     In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil, natural gas and CO₂ wells, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.

     The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2007.

	Three Months Ended
	March 31, 2007
	(in thousands)
Beginning asset retirement obligation, as of 12/31/2006	$	41,107
Liabilities incurred and assumed during period		2,579
Liabilities settled during period		(451	)
Accretion expense		730
Ending asset retirement obligation, as of 3/31/2007	$	43,965

9

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     At March 31, 2007, $1.5 million of our asset retirement obligation was classified in “Accounts payable and accrued liabilities” under current liabilities in our Condensed Consolidated Balance Sheets. Liabilities incurred during the period are primarily for oil and gas properties we acquired during March 2007. We hold cash and liquid investments in escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $8.5 million at March 31, 2007, and $7.6 million at December 31, 2006 and are included in “Other assets” in our Condensed Consolidated Balance Sheets.

Note 4. Notes Payable and Long-term Indebtedness

	March 31,			December 31,
Amounts in thousands	2007			2006
7.5% Senior Subordinated Notes due 2015	$	150,000		$	150,000
7.5% Senior Subordinated Notes due 2013		225,000			225,000
Discount on Senior Subordinated Notes due 2013		(1,166	)		(1,214	)
Senior bank loan		230,000			134,000
Capital lease obligations — Genesis		5,717			5,869
Capital lease obligations		1,183			1,189
Total		610,734			514,844
Less current obligations		686			671
Long-term debt and capital lease obligations	$	610,048		$	514,173

     On March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement, the instrument governing our senior bank loan. The amendments (i) increased the commitment under the facility to $350 million, (ii) permit an additional $150 million add-on to the existing 7.5% Senior Subordinated Notes due 2015, (iii) obtained consent for a sale of our existing CO₂ pipelines to Genesis Energy, L.P., and (iv) reaffirmed the borrowing base at $500 million.

     On April 3, 2007, we issued $150 million of Senior Subordinated Notes as an additional issuance under the instrument governing the 7.5% Senior Subordinated Notes due 2015. The net proceeds were used to repay a portion of the outstanding borrowings under our bank credit facility. See Note 8 — Subsequent Event.

Note 5. Related Party Transactions — Genesis

Interest in and Transactions with Genesis

     Denbury is the general partner and owns an aggregate 9.25% interest in Genesis Energy, L.P. (“Genesis”), a publicly traded master limited partnership. Genesis’ primary business activities include: gathering, marketing and transportation of crude oil and natural gas, and wholesale marketing of CO₂, primarily in Mississippi, Texas, Alabama and Florida.

     We are accounting for our 9.25% ownership in Genesis under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore we do not consolidate Genesis. Our equity in Genesis’ net income for the three months ended March 31, 2007 and 2006 was $0.1 million and $0.2 million, respectively. Denbury received pro-rata distributions from Genesis of $0.2 million during each of the three months ended March 31, 2007 and 2006. We also received $30,000 in each of these periods in directors’ fees for certain officers of Denbury that are board members of Genesis. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.

Oil Sales and Transportation Services

     Prior to September 2004, including the period prior to our investment in Genesis, we sold certain of our oil production to Genesis. Beginning in September 2004, we discontinued most of our direct sales to Genesis and began to transport our crude oil using Genesis’ common carrier pipeline to a sales point where it is sold to third party purchasers. For these transportation services, we pay Genesis a fee for the use of their pipeline and trucking services. In the first three months of 2007 and 2006, we expensed $1.1 million and $1.0 million, respectively, for these transportation services.

10

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Transportation Leases

     In late 2004 and early 2005, we entered into pipeline transportation agreements with Genesis to transport our crude oil from certain of our fields in Southwest Mississippi, and to transport CO₂ from our main CO₂pipeline to Brookhaven Field for our tertiary operations. We have accounted for these agreements as capital leases. The pipelines held under these capital leases are classified as property and equipment and are amortized using the straight-line method over the lease terms. Lease amortization is included in depreciation expense. The related obligations are recorded as debt. At March 31, 2007 and December 31, 2006, we had $5.7 million and $5.9 million, respectively, of capital lease obligations with Genesis recorded as liabilities in our Consolidated Balance Sheets, of which $0.6 million was current in both periods.

CO₂Volumetric Production Payments

     During 2003 through 2005, we sold 280.5 Bcf of CO₂ to Genesis under three separate volumetric production payment agreements. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and recognize such revenue as CO₂ is delivered under the volumetric production payments. At March 31, 2007 and December 31, 2006, $32.0 million and $32.9 million, respectively, was recorded as deferred revenue, of which $4.1 million was included in current liabilities at both March 31, 2007 and December 31, 2006. We recognized deferred revenue of $1.0 million and $0.9 million for the three months ended March 31, 2007 and 2006, respectively, for deliveries under these volumetric production payments. We provide Genesis with certain processing and transportation services in connection with transporting CO₂ to their industrial customers for a fee of approximately $0.17 per Mcf of CO₂. For these services, we recognized revenues of $1.1 million and $1.0 million for the three months ended March 31, 2007 and 2006, respectively.

     At March 31, 2007 and December 31, 2006, we had a net receivable from Genesis of $0.1 million at each period end associated with all of the transactions described above.

Note 6. Derivative Instruments and Hedging Activities

Oil and Gas Derivative Contracts

     We do not apply hedge accounting treatment to our oil and 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 Commodity Derivative Expense in our Condensed Consolidated Statements of Operations.

     The following is a summary of “Commodity Derivative Expense” included in our Condensed Consolidated Statements of Operations:

	Three Months Ended March 31,
(In Thousands)	2007			2006
(Receipt) payment on settlements of derivative contracts — Oil	$	(126	)	$	768
(Receipt) payment on settlements of derivative contracts — Gas		(8,125	)		—
Fair value adjustments to derivative contracts		35,158			10,862
Commodity derivative expense	$	26,907		$	11,630

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Oil and Natural Gas Commodity Derivative Contracts at March 31, 2007:

Crude Oil Contracts at March 31, 2007:

					Estimated
					Fair Value at
	NYMEX Contract Prices Per Bbl				March 31, 2007
Type of Contract and Period	Bbls/d		Swap Price		(In Thousands)
Swap Contracts
April 2007 - Dec. 2007		2,000	$	58.93	$	(5,295	)
Jan. 2008 - Dec. 2008		2,000		57.34		(8,644	)

Natural Gas Contracts at March 31, 2007:

					Estimated
					Fair Value at
	NYMEX Contract Prices Per MMBtu				March 31, 2007
Type of Contract and Period	MMBtu/d		Swap Price		(In Thousands)
Swap Contracts
April 2007 - Dec. 2007		20,000	$	7.99	$	(1,330	)
April 2007 - Dec. 2007		40,000		7.96		(2,984	)
April 2007 - Dec. 2007		15,000		7.95		(1,159	)

     At March 31, 2007, our oil and natural gas derivative contracts were recorded at their fair value, which was a net liability of $19.4 million.

Interest Rate Lock Derivative Contracts

     In January 2007, we entered into interest rate lock contracts to remove our exposure to possible interest rate fluctuations related to our commitment to the sale-leaseback financing of certain equipment for CO₂ recycling facilities at our tertiary oil fields. The interest rate lock contracts cover two groups of equipment currently being constructed that we have committed to finance with Bank of America Leasing & Capital LLC. This equipment has estimated completion dates during the fourth quarter of 2007 and in mid-year 2008, with total estimated costs of approximately $15 million and $24 million, respectively. We are applying hedge accounting to these contracts as provided under SFAS No. 133. For these instruments designated as interest rate hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Amounts representing hedge ineffectiveness are recorded in earnings. Hedge effectiveness is assessed quarterly based on the total change in the contract’s fair value.

     At March 31, 2007, the interest rate lock contracts have a fair value liability of approximately $842,000 that was recorded in our March 31, 2007 Condensed Consolidating Balance Sheet. We recorded $513,000 (net of taxes of $328,000) in accumulated other comprehensive loss in our March 31, 2007 Condensed Consolidating Balance Sheet and the ineffectiveness totaling $1,000 was recognized as expense in our Condensed Consolidating Statement of Operations for the three months ended March 31, 2007.

Note 7. Condensed Consolidating Financial Information

     Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of Denbury Resources Inc.’s subsidiaries other than minor subsidiaries, except that with respect to our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our equity interest in Genesis are reflected through the equity method by one of our subsidiaries, Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100% owned, directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Balance Sheets

(In Thousands)	March 31, 2007
					Other					Denbury
	Denbury		Denbury		Guarantor					Resources Inc.
	Resources Inc.		Onshore, LLC		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	402,474	$	140,065	$	5,749	$	(403,502	)	$	144,786
Property and equipment		—		2,052,786		22		—			2,052,808
Investment in subsidiaries (equity method)		725,801		—		725,608		(1,440,866	)		10,543
Other assets		155,138		65,339		154		(153,568	)		67,063
Total assets	$	1,283,413	$	2,258,190	$	731,533	$	(1,997,936	)	$	2,275,200
Liabilities and Stockholders’ Equity
Current liabilities	$	322	$	601,993	$	5,456	$	(403,502	)	$	204,269
Long-term liabilities		150,000		941,132		276		(153,568	)		937,840
Stockholders’ equity		1,133,091		715,065		725,801		(1,440,866	)		1,133,091
Total liabilties and stockholders’ equity	$	1,283,413	$	2,258,190	$	731,533	$	(1,997,936	)	$	2,275,200

(In Thousands)	December 31, 2006
					Other					Denbury
	Denbury		Denbury		Guarantor					Resources Inc.
	Resources Inc.		Onshore, LLC		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	392,372	$	180,476	$	3,662	$	(393,241	)	$	183,269
Property and equipment		—		1,879,742		26		—			1,879,768
Investment in subsidiaries (equity method)		709,611		—		709,020		(1,407,991	)		10,640
Other assets		154,076		64,391		154		(152,461	)		66,160
Total assets	$	1,256,059	$	2,124,609	$	712,862	$	(1,953,693	)	$	2,139,837
Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	590,602	$	3,037	$	(393,241	)	$	200,398
Long-term liabilities		150,000		835,627		214		(152,461	)		833,380
Stockholders’ equity		1,106,059		698,380		709,611		(1,407,991	)		1,106,059
Total liabilties and stockholders’ equity	$	1,256,059	$	2,124,609	$	712,862	$	(1,953,693	)	$	2,139,837

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations

(In Thousands)	Three Months Ended March 31, 2007
						Other						Denbury
	Denbury			Denbury		Guarantor						Resources Inc.
	Resources Inc.			Onshore, LLC		Subsidiaries			Eliminations			Consolidated
Revenues	$	2,813		$	173,992	$	16		$	(2,813	)	$	174,008
Expenses		2,904			146,202		614			(2,813	)		146,907
Income before the following:		(91	)		27,790		(598	)		—			27,101
Equity in net earnings of subsidiaries		16,703			—		17,345			(33,901	)		147
Income before income taxes		16,612			27,790		16,747			(33,901	)		27,248
Income tax provision		(4	)		10,592		44			—			10,632
Net income	$	16,616		$	17,198	$	16,703		$	(33,901	)	$	16,616

(In Thousands)	Three Months Ended March 31, 2006
						Other						Denbury
	Denbury			Denbury		Guarantor						Resources Inc.
	Resources Inc.			Onshore, LLC		Subsidiaries			Eliminations			Consolidated
Revenues	$	2,813		$	176,093	$	—		$	—		$	178,906
Expenses		2,903			104,064		431			—			107,398
Income before the following:		(90	)		72,029		(431	)		—			71,508
Equity in net earnings of subsidiaries		43,858			—		44,343			(87,961	)		240
Income before income taxes		43,768			72,029		43,912			(87,961	)		71,748
Income tax provision		(10	)		27,926		54			—			27,970
Net income	$	43,778		$	44,103	$	43,858		$	(87,961	)	$	43,778

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Cash Flows

(In Thousands)	Three Months Ended March 31, 2007
							Other					Denbury
	Denbury			Denbury			Guarantor					Resources Inc.
	Resources Inc.			Onshore, LLC			Subsidiaries		Eliminations			Consolidated
Cash flow from operations	$	33		$	93,074		$	238	$	—		$	93,345
Cash flow from investing activities		(7,770	)		(215,615	)		—		7,770			(215,615	)
Cash flow from financing activities		7,770			103,404			—		(7,770	)		103,404
Net increase (decrease) in cash		33			(19,137	)		238		—			(18,866	)
Cash, beginning of period		1			52,225			1,647		—			53,873
Cash, end of period	$	34		$	33,088		$	1,885	$	—		$	35,007

(In Thousands)	Three Months Ended March 31, 2006
							Other				Denbury
	Denbury			Denbury			Guarantor				Resources Inc.
	Resources Inc.			Onshore, LLC			Subsidiaries		Eliminations		Consolidated
Cash flow from operations	$	(4,458	)	$	106,762		$	208	$	—	$	102,512
Cash flow from investing activities		—			(347,684	)		—		—		(347,684	)
Cash flow from financing activities		4,458			105,609			—		—		110,067
Net increase (decrease) in cash		—			(135,313	)		208		—		(135,105	)
Cash, beginning of period		1			164,408			680		—		165,089
Cash, end of period	$	1		$	29,095		$	888	$	—	$	29,984

Note 8. Subsequent Event

     On April 3, 2007, we sold $150 million of Senior Subordinated Notes as an additional issuance under the December 2005 indenture governing our 7.5% Senior Subordinated Notes due 2015. The notes, which carry a coupon rate of 7.5%, were sold at 100.5% of par, which equates to an effective yield to maturity of approximately 7.4%. The net proceeds from the sale were approximately $149.2 million, which we used to repay a portion of the outstanding borrowings under our bank credit facility.

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DENBURY RESOURCES INC.

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

     You should read the following in conjunction with our financial statements contained herein and in our Form 10-K for the year ended December 31, 2006, 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.

     We are a growing independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest carbon dioxide (“CO₂”) reserves east of the Mississippi River used for tertiary oil recovery, and hold significant operating acreage onshore Louisiana, Alabama, in the Barnett Shale play near Fort Worth, Texas, and properties in Southeast Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have five primary field offices located in Houma, Louisiana; Laurel, Mississippi; McComb, Mississippi; Brandon, Mississippi; and Cleburne, Texas.

Overview

     Operating results.During the first quarter of 2007, we had a record quarterly production rate that averaged 38,305 BOE/d, an 8% increase over production levels in the first quarter of 2006, with significant increases in our tertiary oil and Barnett shale production, partially offset by significant production declines in Louisiana. Higher operating costs, a $35.2 million ($21.4 million after tax) mark-to-market pre-tax charge to earnings primarily related to our 2007 natural gas swaps as a result of higher natural gas price futures at March 31, 2007 than at December 31, 2006, and lower overall commodity prices offset the revenue impact of higher production, causing a 62% decrease in net income between the comparable first quarters. The net result was net income of $16.6 million during the first quarter of 2007 as compared to $43.8 million of net income during the first quarter of 2006. Last year’s first quarter 2006 net income included the effect of approximately $10.9 million ($6.6 million after tax) of mark-to-market charges related to derivative contracts in place at that time.

     Although we had a large non-cash mark-to-market value charge in the first quarter of 2007 on our oil and natural gas derivative contracts, we had net cash receipts of $8.3 million on settlements of our derivative contracts, primarily on our 2007 natural gas swaps, as compared to total cash payments of $0.8 million during the first quarter of 2006.

     All of our expenses, other than interest expense, increased on both an absolute and per BOE basis during the first quarter of 2007 due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), (iii) the timing impact of the continued expansion of our tertiary operations in which we expense the cost of our CO₂ and other operating costs even though production response to the injections will lag behind (see CO₂ operations for a more thorough discussion), and (iv) higher compensation expense resulting from additional employees and increased salaries which we consider necessary in order to remain competitive in the industry. Even though our average debt level was 19% higher in the first quarter of 2007 as compared to levels in the first quarter of 2006, because of the significant expenditures made during 2006 and 2007 on unevaluated properties, we capitalized $4.0 million of interest expense in the first quarter of 2007 related to those unevaluated properties, as compared to $0.3 million of interest capitalized during the first quarter of 2006, reducing our overall interest expense between the two periods by 26%.

     While overall costs were higher in 2007’s first quarter than in the prior first quarter period, the rate of inflation in our industry during 2007 appears to have moderated, and in some cases, we are beginning to see modest cost reductions. Likewise, although goods and services are still tight, there were signs of improvement with regard to overall availability, although there are still supply issues and long lead times for certain items, as for example, compressors used in our tertiary recycle facilities and construction services for pipelines. It is difficult to forecast price trends and supply and service availability, which if adverse, can significantly impact both operating costs and capital expenditures, as well as cause delays in achieving our anticipated production targets.

     Overview of tertiary operations.Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of

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DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CO₂ that we own drive the play. Please refer to the section entitled “CO₂ Operations” below and contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2006 Form 10-K for further information regarding these operations, their potential, and the ramifications of this focus.

     Oil production from our tertiary operations increased to an average of 11,779 BOE/d in the first quarter of 2007, a 21% increase over the first quarter 2006 tertiary production level of 9,758 BOE/d and a 17% increase over the fourth quarter 2006 production level. Production from our Phase II operations (Eucutta and Martinville Fields) contributed 959 BOE/d to the increase over the prior year’s first quarter production, with the balance from all of our Phase I fields except Little Creek Field, which is on a gradual decline.

     Recent Proposed Acquisition by Genesis Energy.On April 26, 2007, Genesis Energy, L.P. (“Genesis”), a master limited partnership of which Denbury is the general partner, announced that they had entered into an agreement to acquire several energy related businesses from the Davison family of Ruston, Louisiana at an estimated price of $560 million. These businesses include a trucking operation for petroleum products and other bulk commodities, terminal storage of refined petroleum products, a refinery service operation which processes sour gas streams at several refining operations, and a wholesale petroleum products marketing business. The acquisition is subject to various customary closing conditions and is expected to close early in the third quarter of 2007. The acquisition will be funded by a combination of debt from the Genesis bank credit facility and Genesis common units to be issued to the seller.

     We have previously discussed with Genesis that upon Genesis achieving certain goals, primarily the acquisition of other economic projects that are not related to Denbury, that we would undertake to sell certain Denbury assets to Genesis based upon acquisition by Genesis of $1.50 of non-Denbury-related acquisitions for every $1.00 of sales with Denbury. As a result of the recently announced Genesis acquisition, we anticipate that during 2007 we will sell our two existing significant CO₂ pipelines to Genesis by entering into sale-leaseback transactions, with a total currently estimated value of between $200 million and $250 million. This “drop-down” transaction would be subject to, among other things, negotiation of specific terms, the approval of the board of directors of both entities, and the receipt of fairness opinions for both companies, and is expected to occur a few months following closing of their announced acquisition. We would anticipate a similar transaction with Genesis for the new CO₂ pipeline we are building from Jackson Dome to Tinsley and Delhi Fields once that pipeline is completed, forecasted at this time to be in 2008. If in future periods Genesis is able to complete additional acquisitions of sufficient size with acceptable economic returns, we would anticipate a similar transaction with Genesis of our proposed 280 to 300 mile CO₂ pipeline from Southern Louisiana to Hastings Field, located near Houston, Texas, probably in 2010.

     Recent Acquisition.On March 31, 2007, we completed an acquisition of six producing oil fields, two of which are future potential CO₂ tertiary oil flood candidates, collectively called the Seabreeze Complex, located near Houston, Texas, at a cost of approximately $41.7 million. Tertiary operations are not expected to commence at these fields until 2010 or 2011, following anticipated completion of the 280 to 300 mile CO₂ pipeline from Louisiana to Hastings Field (also near Houston). The acquisition was funded with bank financing under our existing credit facility. These fields are currently producing approximately 400 BOE/d net to the acquired interests, and have estimated proved conventional reserves of approximately 525 MBOE. We operate all of these fields and own the majority of the working interests.

     April 2007 Debt Issuance.On April 3, 2007, we issued $150 million of 7.5% Senior Subordinated Notes due 2015 as an additional issuance under our existing December 2005 indenture governing our December 2005 sale of $150 million of 7.5% Senior Subordinated Notes due 2015. The notes were issued at 100.5% of par, which equates to an effective yield to maturity of 7.4%. The net proceeds from the sale were approximately $149.2 million, which we used to repay a portion of the outstanding borrowings under our bank credit facility.

Capital Resources and Liquidity

     Our current 2007 capital budget is $670 million, excluding any acquisitions, and including approximately $20 million of uncompleted projects carried over from 2006. Approximately 60% of our 2007 budget is expected to be spent on tertiary related operations, approximately 20% in the Barnett Shale area, and less than 10% on exploration projects, with the balance spent on our conventional properties in Mississippi or Louisiana. This capital program

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

includes an estimated $110 million for a CO₂ pipeline from our CO₂ source at Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during 2006. Based on oil and natural gas commodity futures prices as of the end of April 2007, this budget is $200 million to $250 million greater than our anticipated cash flow from operations, a much greater shortfall than we have had in recent years. We plan to fund substantially all of this shortfall by selling our two existing significant CO₂ pipelines to Genesis by entering into sale-leaseback transactions (see “Overview — Recent Proposed Acquisition by Genesis Energy”). Any unfunded portion would be financed with incremental bank debt. If a transaction with Genesis is not consummated, we would plan to fund the shortfall with bank debt and could potentially reduce our capital budget later in the year.

     As a result of our April 2007 $150 million subordinated debt offering (see “Overview — Recent Debt Issuance”) which repaid approximately $150 million of bank debt, as of April 30, 2007, we had $100 million of bank debt outstanding on a $500 million borrowing base, leaving us significant incremental borrowing capacity, more than we currently plan or desire to use.

     We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, during the last few years as commodity prices have increased, we have increased our capital budget throughout the year. As a result of the recent cost inflation in our industry, many of our recent budget increases have related to escalating costs rather than additional projects. Even though there are signs that this inflationary trend is subsiding, if costs do rise or we spend more than our estimated or forecasted amounts, we will either have to increase our capital budget or consider the elimination of a portion of our planned projects.

     We also continue to pursue additional acquisitions of mature oil fields that we believe have potential as future tertiary flood candidates. These possible acquisitions are difficult to forecast and the purchase price can vary widely depending on the levels of existing production and conventional proved reserves and commodity prices. Any additional acquisitions would be funded, at least temporarily, with bank or other debt, although if significant, the acquisition would likely be ultimately funded with more permanent capital such as subordinated debt and/or additional equity.

     Amendment to our bank credit facility.On March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative agent. The amendment (i) increased the commitment amount that the banks are committed to fund from $250 million to $350 million, (ii) reconfirmed the borrowing base of $500 million, (iii) authorized the $150 million subordinated debt offering (see “Overview — Recent Debt Issuance”), and (iv) authorized us to enter into a sale-leaseback type transaction for our CO₂ pipelines, not to exceed $300 million, with Genesis, in the type of transaction contemplated and discussed above (see “Overview — Recent Proposed Acquisition by Genesis”). With regard to our bank credit facility, the borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($350 million), up to the borrowing base limit ($500 million), although the banks are not obligated to fund any amount in excess of the commitment amount. At April 30, 2007, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and $100 million of bank debt.

Sources and Uses of Capital Resources

     During the first quarter of 2007, we spent $139.0 million on oil and natural gas exploration and development expenditures, $31.4 million on CO₂ exploration and development expenditures, and approximately $39.1 million on property acquisitions, for total capital expenditures of approximately $209.5 million. Our exploration and development expenditures included approximately $74.2 million incurred for drilling, $7.5 million for geological, geophysical and acreage expenditures and $57.3 million for facilities and recompletion costs. We funded these expenditures with $93.3 million of cash flow from operations, $96.0 million of bank borrowings, $18.9 million of cash and funded the balance with other working capital. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under “Results of Operations-Operating Results”) was $104.2 million for the first quarter of 2007, while cash flow from operations for the same period, the GAAP measure, was $93.3 million.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     During the first quarter of 2006, we spent $118.6 million on oil and natural gas exploration and development expenditures, $11.0 million for CO₂ exploration and development expenditures, and approximately $252.4 million on property acquisitions, for total capital expenditures of approximately $382.0 million. Our exploration and development expenditures included approximately $56.6 million incurred for drilling, $6.1 million for geological, geophysical and acreage expenditures and $55.9 million incurred for facilities and recompletion costs. We funded these expenditures with $102.5 million of cash flow from operations, $100 million of bank borrowings, a $10.0 million increase in our accrued capital expenditures and funded the balance with working capital, predominately cash from the December 2005 issuance of $150 million of subordinated debt. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under “Results of Operations-Operating Results”) was $107.8 million for the first quarter of 2006, while cash flow from operations for the same period, the GAAP measure, was $102.5 million.

Off-Balance Sheet Arrangements

Commitments and Obligations

     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 the proved reserve reports. Our derivative contracts are discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements. Neither the amounts nor the terms of these commitments or contingent obligations have changed significantly from the year-end 2006 amounts reflected in our Form 10-K filed in March 2007, except for a commitment to a new building lease expected to commence in mid-2008 representing future payments of approximately $20 million over 136 months. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Off-Balance Sheet Arrangements — Commitments and Obligations” contained in our 2006 Form 10-K for further information regarding our commitments and obligations.

Results of Operations

CO₂Operations

     Our focus on CO₂ operations is becoming an ever-increasing part 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 and other public disclosures. In addition to its long-term effect, this shift in focus 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 2006 Form 10-K for further information regarding these matters.

     During 2007 we plan to drill additional CO₂ source wells to further increase our production capacity and reserves. We estimate that we are currently capable of producing between 550 MMcf/d and 600 MMcf/d of CO_2, and following the anticipated completion of two additional wells during the second quarter of 2007, we should be capable of producing between 650 MMcf/d and 700 MMcf/d. During the first quarter of 2007 our CO₂ production averaged 448 MMCf/d, as compared to an average of approximately 394 MMcf/d during the fourth quarter of 2006. We used 81% of this production, or 362 MMcf/d, in our tertiary operations during the first quarter of 2007 and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.

     Oil production from our tertiary operations increased to an average of 11,779 BOE/d in the first quarter of 2007, a 21% increase over the first quarter 2006 tertiary production level of 9,758 BOE/d, and 17% higher than fourth quarter 2006 tertiary production levels. The table below shows our tertiary oil production by field for the first quarter of 2007 and all quarters of 2006. We are beginning to see improved response in our newer floods at Smithdale, Martinville, Eucutta and Soso Fields, most of which were initiated during 2006. In addition, we continue to see improved response at most of our other floods except Little Creek Field, which is a mature flood and is expected to continue to decline over the next several years.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First
	Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2006		2006		2006		2006		2007
Phase I:
Brookhaven		547		798		965		1,014		1,422
Little Creek & Lazy Creek		3,006		3,056		2,623		2,279		2,117
Mallalieu (East and West)		5,219		5,385		5,243		4,994		5,470
McComb & Olive		932		1,062		1,242		1,467		1,497
Smithdale		54		74		41		63		314
Phase II:
Martinville		—		—		—		24		320
Eucutta		—		—		—		187		614
Soso		—		—		—		—		25
Total tertiary oil production		9,758		10,375		10,114		10,028		11,779

     We spent approximately $0.17 per Mcf to produce our CO₂during the first quarter of 2007, lower than our 2006 average of $0.19 per Mcf, primarily due to (a) production increases that more than offset our production cost increases and (b) lower royalty expense due to lower oil prices in the first quarter of 2007. Due to these same reasons, our estimated total cost per thousand cubic feet of CO₂during the first quarter of 2007 was approximately $0.25, after inclusion of depreciation and amortization expense, also down from the 2006 average of $0.28 per Mcf.

     For the first quarter of 2007, our operating costs for our tertiary properties averaged $20.27 per BOE, higher than the prior year’s first quarter average of $15.02 per BOE, but slightly lower than our fourth quarter 2006 average of $20.58 per BOE. The higher costs are primarily due to general cost inflation in the industry and the new floods initiated last year, which resulted in higher CO₂ costs, higher fuel and energy costs and higher rental payments on leased equipment. Because we expense all lease operating costs, including injection costs, associated with starting a new flood, we expect the lease operating expense per BOE for tertiary operations to initially be high, until production increases significantly. For example, for the first quarter of 2007, operating costs per BOE for our Phase I properties which are generally more developed than our Phase II properties, were $17.04 per BOE, as compared to tertiary operating costs of $55.93 per BOE for Phase II, an area which is just beginning to respond. In comparison, our operating costs for Mallalieu Field, currently our highest volume tertiary producer, was $10.36 per BOE during the same period. We expect our operating costs to average between $13 and $15 per BOE over the life of a tertiary flood, even though our recent average tertiary operating costs have been higher, as we continue to implement additional floods.

Operating Results

     As summarized in the “Overview” section above and discussed in more detail below, during the 2007 period our record production was more than offset by higher operating expenses, particularly because of a large mark-to-market charge on our derivative contracts, resulting in lower quarterly earnings. Because the mark-to-market charge is not a cash item, our cash flow from operations was down only slightly between the two periods, as lower overall commodity prices and higher operating expenses offset higher production.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Three Months Ended
	March 31,
Amounts in thousands, except per share amounts	2007			2006
Net income	$	16,616		$	43,778
Net income per common share — basic		0.14			0.39
Net income per common share — diluted		0.13			0.37
Adjusted cash flow from operations (see below)	$	104,227		$	107,849
Net change in assets and liabilities relating to operations		(10,882	)		(5,337	)
Cash flow from operations (1)	$	93,345		$	102,512

(1) Net cash flow provided by operations as per the Unaudited Condensed Consolidated Statements of Cash Flows.

     Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities, as calculated from our Unaudited Condensed Consolidated Statements of Cash Flows. Cash flow from operations is the GAAP measure as presented in our Unaudited Condensed Consolidated Statements of Cash Flows. In our discussion herein, we have elected to discuss these two components of cash flow provided by operations separately.

     Adjusted cash flow from operations, the non-GAAP measure, measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe it is important to consider adjusted cash flow from operations separately, as we believe it can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during that year. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices or significant changes in drilling activity.

     The net change in assets and liabilities relating to operations is also important as it does require or provide additional cash for use in our business; however, we prefer to discuss its effect separately. For instance, as noted above, during the first quarter of both years, we used cash to fund a net increase in our other working capital items. During the first quarter of 2007, this was primarily caused by an increase in trade receivables and prepaid expenses as a result of our higher level of activity. During the first quarter of 2006, this was primarily caused by an increase in other current assets related to a deposit for post-closing items from the January acquisition in the first quarter of 2006. These increases were partially offset by changes in other current assets and liabilities.

21

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     Certain of our operating results and statistics for the comparative first quarters of 2007 and 2006 are included in the following table.

	Three Months Ended
	March 31,
	2007			2006
Average daily production volumes
Bbls/d		24,054			22,211
Mcf/d		85,506			79,452
BOE/d(1)		38,305			35,454
Operating revenues (in thousands)
Oil sales	$	118,132		$	113,441
Natural gas sales		51,002			62,102
Total oil and natural gas sales	$	169,134		$	175,543
Oil and gas derivative contracts(2)(in thousands)
Cash receipt (payment) on settlement of derivative contracts	$	8,251		$	(768	)
Non-cash fair value adjustments		(35,158	)		(10,862	)
Total expense from oil and gas derivative contracts	$	(26,907	)	$	(11,630	)
Operating expenses (in thousands)
Lease operating expenses	$	50,557		$	36,172
Production taxes and marketing expenses(3)		10,204			8,087
Total production expenses	$	60,761		$	44,259
Non-tertiary CO2 operating margin (in thousands)
CO2 sales and transportation fees(4)	$	3,091		$	1,988
CO2 operating expenses		(703	)		(645	)
Non-tertiary CO2 operating margin	$	2,388		$	1,343
Unit prices — including impact of derivative settlements(2)
Oil price per Bbl	$	54.63		$	56.36
Gas price per Mcf		7.68			8.68
Unit prices — excluding impact of derivative settlements(2)
Oil price per Bbl	$	54.57		$	56.75
Gas price per Mcf		6.63			8.68
Oil and gas operating revenues and expenses per BOE(1):
Oil and natural gas revenues	$	49.06		$	55.01
Oil and gas lease operating expenses	$	14.66		$	11.34
Oil and gas production taxes and marketing expense		2.96			2.53
Total oil and gas production expenses	$	17.62		$	13.87

(1)	Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).
(2)	See also “Market Risk Management” below for information concerning the Company’s derivative transactions.
(3)	Includes transportation expenses paid to Genesis of $1.1 million in each period.
(4)	Includes deferred revenue of $1.0 million and $0.9 million for 2007 and 2006, respectively, associated with volumetric production payments and $1.1 million and $1.0 million, respectively, of transportation income, both from Genesis.

22

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     Production: Production by area for each of the quarters of 2006 and the first quarter of 2007 is listed in the following table.

	Average Daily Production (BOE/d)
	First		Second		Third			Fourth		First
	Quarter		Quarter		Quarter			Quarter		Quarter
Operating Area	2006		2006		2006			2006		2007
Mississippi — non-CO2 floods		12,455		12,633		13,069			12,808		12,738
Mississippi — CO2 floods		9,758		10,375		10,114			10,028		11,779
Onshore Louisiana		8,349		8,623		8,221			6,572		5,591
Barnett Shale		3,953		4,621		4,952			5,925		6,989
Alabama		917		1,213		1,215			1,243		1,223
Other(1)		22		9		(10	)		43		(15	)
Total Company		35,454		37,474		37,561			36,619		38,305

     As outlined in the above table, production in the first quarter of 2007 increased 8% over first quarter of 2006 levels and 5% over fourth quarter 2006 levels. This increase from the first quarter of 2006 is primarily due to increased production from our tertiary operations and Barnett Shale, offset in part by decreases in our onshore Louisiana wells. Also, Alabama production in 2006 reflected only two months activity as this production is primarily from Citronelle Field that we acquired at the end of January 2006. The increase in our tertiary operations is discussed above under “Results of Operations – CO₂ Operations”.

     Production in the Mississippi – non-CO₂ floods area was up slightly from the prior year’s first quarter and about the same as the fourth quarter of 2006 level, as our drilling activity in the Heidelberg area Selma Chalk (natural gas) has helped offset the gradual declines in oil production.

     Our Barnett Shale production increased approximately 77% from the prior year quarter’s level due to our successful drilling activity over the last year. During 2006, we drilled 46 horizontal wells and we drilled 12 wells in the first quarter of 2007. We had four rigs working in the area during most of the first quarter of 2007, but we have currently reduced our rig count in this area to three, and will likely make a further reduction to two rigs as our planned drilling of 35 to 40 new wells is ahead of schedule. We do not anticipate any significant production increases from the Barnett Shale during the remainder of 2007, and production may decline later this year as it is unlikely that we will be able to maintain current production levels with only two rigs.

     The decrease in onshore Louisiana production is due primarily to the expected relatively rapid depletion of wells in this area. Also, since 2005 we have focused less of our spending in this area and therefore drilled fewer wells than we have historically. During the first quarter of 2007, we reached total depth on the second well in our Gumbo Prospect, the State Lease 18380 #2. Our analysis of this well indicated that minimal reserves were found and we decided to sidetrack this well. We expect to know the result of this well sometime during the second quarter of 2007.

     Oil and Natural Gas Revenues:Oil and natural gas revenues for the first quarter of 2007 decreased $6.4 million, or 4%, from revenues in the first quarter of 2006, as lower commodity prices offset higher production. The decrease in overall commodity prices in the first quarter of 2007 decreased revenues by $20.5 million, or 12%, when comparing the two first quarters of 2006 and 2007, while the increase in production in the first quarter of 2007 increased oil and natural gas revenues by $14.1 million, or 8%, as compared to the prior year’s first quarter. Our realized natural gas prices (excluding hedges) for the first quarter of 2007 averaged $6.63 per Mcf, a 24% decrease from the average of $8.68 per Mcf realized during the first quarter of 2006, and our realized oil prices (excluding hedges) for the first quarter of 2007 averaged $54.57 per Bbl, a 4% decrease from the $56.75 per Bbl average realized in the first quarter of 2006. On a combined BOE basis, our realized commodity prices were 11% lower in the first quarter of 2007 than in the first quarter of 2006.

23

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The differentials between our net realized oil prices (excluding commodity derivative contracts) and NYMEX prices improved in the first quarter of 2007 as compared to the differentials in both the first quarter of 2006 and fourth quarter of 2006 differentials. Our average oil price NYMEX differential for the first quarter of 2007 was approximately $3.73 per Bbl as compared to $6.71 per Bbl during the first quarter of 2006 and $5.92 per Bbl during the fourth quarter of 2006. This improvement in the NYMEX differential in the first quarter of 2007 was related to higher prices received for both our light sweet barrels and our sour barrels primarily as a result of NYMEX (WTI) prices being depressed due to lack of available storage capacity in the mid-continent area, an oversupply of crude from Canada, capacity/transportation issues in moving crude oil out of the Cushing, Oklahoma area and unanticipated refinery outages.

     Our average natural gas differential relative to NYMEX moved in an unfavorable direction as compared to the differential in the first quarter of 2006, but improved slightly from fourth quarter of 2006 differentials. Our average natural gas differential for the first quarter of 2007 was a negative variance of approximately $0.51 per Mcf, as compared to a positive variance of $0.78 per Mcf during the first quarter of 2006 and a negative variance of $0.64 per Mcf during the fourth quarter of 2006. The positive variance in the first quarter of 2006 was primarily due to the significant weakening of natural gas prices during that quarter and conversely, the negative variance in the first quarter of 2007 is primarily due to a strengthening of natural gas prices during that quarter. Since most of our natural gas is sold on an index price that is set near the first of each month, the variance will decrease if NYMEX natural gas prices consistently decrease during the quarter and vice versa.

     Oil and Natural Gas Derivative Contracts:We received proceeds of $8.3 million on settlements of our oil and natural gas derivative contracts during the first quarter of 2007, as compared to cash payments of $0.8 million we made during the first quarter of 2006. The 2007 receipts primarily related to the 75 MMcf/d of natural gas swaps for calendar 2007 that we entered into in December 2006. Due to rising natural gas prices during the period, the market value of those same natural gas swaps declined substantially during the period, resulting in a $32.4 million mark-to-market value adjustment at March 31, 2007. Our total mark-to-market expense was $35.2 million during the first quarter of 2007, as compared to an expense of $10.9 million in the first quarter of 2006. Because we do not utilize hedge accounting for our commodity derivative contracts, the adjustments in the fair value of these contracts is recognized currently in our income statement. See “Market Risk Management” for additional information regarding our derivative activities and Note 6 to the Condensed Consolidated Financial Statements.

     Production Expenses:Our lease operating expenses increased between the comparable first quarters on both a per BOE basis and in absolute dollars, primarily as a result of (i) our increasing emphasis on tertiary operations (see discussion of those expenses under “CO₂ Operations”above), (ii) higher overall industry costs, (iii) increased personnel and related costs, (iv) higher fuel and energy costs to operate our properties, (v) increasing lease payments for certain of our tertiary operating facilities, and (vi) higher workover costs.

     During the first quarter of 2007, operating costs averaged $14.66 per BOE, up from $11.34 per BOE in the first quarter of 2006, and up slightly from $13.99 per BOE in the fourth quarter of 2006. Operating expenses on our tertiary operations increased from $13.2 million in the first quarter of 2006 to $21.5 million during the first quarter of 2007, as a result of our increased tertiary activity level. Tertiary operating expenses were particularly impacted by higher power and energy costs, expenses on floods from which there was minimal production response to date, and payments on leased facilities and equipment (see “CO₂ Operations” above). Our emphasis on tertiary operations is expected to continue, which may further increase our cost per BOE as tertiary production becomes a more significant portion of our total production and operations.

     Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes and therefore were higher in the first quarter of 2007 than in the comparable quarter of 2006. Transportation and plant processing fees were about $1.5 million higher in the first quarter of 2007 than in the first quarter of 2006.

24

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General and Administrative Expenses

     General and administrative (“G&A”) expenses increased 16% between the respective first quarters as set forth below:

	Three Months Ended
	March 31,
Amounts in Thousands Except Per BOE and Employee Data	2007			2006
Gross G&A expense	$	26,770		$	21,340
State franchise taxes		718			412
Operator labor and overhead recovery charges		(13,806	)		(9,909	)
Capitalized exploration and development costs		(2,248	)		(1,976	)
Net G&A expense	$	11,434		$	9,867
Average G&A cost per BOE	$	3.32		$	3.09
Employees as of March 31		629			507

     Gross G&A expenses increased $5.4 million, or 25%, between the first quarters of 2006 and 2007. Approximately $4.3 million of the increase in gross G&A expenses is related to increases in personnel related costs, due primarily to the increase in employees and increase in wages resulting from the 5% mid-year pay increase for all employees in mid-2006 and year end pay increases which averaged 4.4%. During 2006, we increased our employee count by 30% and we further increased our employee count by approximately 6% during the first quarter of 2007. Stock compensation expense reflected in gross G&A expenses was approximately $3.1 million for the first quarter of 2007 and $3.5 million for the first quarter of 2006.

     The increase in gross G&A was offset in part by an increase in operator labor and overhead recovery charges in the first quarter of 2007. Our well operating agreements allow us, as operator, to charge labor to a well and to charge 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 39% between the first quarters of 2006 and 2007. Capitalized exploration and development costs also increased between the comparable periods in 2006 and 2007, primarily as a result of increased compensation costs.

     The net effect was a 16% increase in net G&A expense between the respective first quarters. On a per BOE basis, G&A costs increased 7% in the first quarter of 2007 as compared to levels of those costs in the first quarter of 2006, a lower percentage increase than the increase in gross costs as a result of the higher production levels.

Interest and Financing Expenses

	Three Months Ended
	March 31,
Amounts in thousands, except per BOE data	2007			2006
Cash interest expense	$	9,839		$	8,268
Non-cash interest expense		269			260
Less: Capitalized interest		(4,033	)		(274	)
Interest expense	$	6,075		$	8,254
Interest and other income	$	1,783		$	1,375
Average net cash interest expense per BOE(1)	$	1.18		$	2.07
Average debt outstanding	$	530,586		$	446,953
Average interest rate(2)		7.4	%		7.4	%

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

25

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     Interest expense decreased $2.2 million, or 26%, comparing the first quarters of 2006 and 2007. This decrease is primarily due to higher capitalized interest of approximately $3.8 million in the first quarter of 2007, due primarily to interest capitalized on our significant unevaluated properties, most of which were acquired in 2006. The increase in capitalized interest is partially offset by a 19% increase in our average debt level between the two quarters.

Depletion, Depreciation and Amortization

	Three Months Ended
	March 31,
Amounts in thousands, except per BOE data	2007		2006
Depletion and depreciation of oil and natural gas properties	$	35,966	$	29,317
Depletion and depreciation of CO2 assets		2,680		1,789
Asset retirement obligations		730		571
Depreciation of other fixed assets		1,651		1,066
Total DD&A	$	41,027	$	32,743
DD&A per BOE:
Oil and natural gas properties	$	10.64	$	9.37
CO2 assets and other fixed assets		1.26		0.89
Total DD&A cost per BOE	$	11.90	$	10.26

     Our depletion, depreciation and amortization (“DD&A”) rate on a per BOE basis increased 3% over the fourth quarter of 2006 DD&A rate of $11.60 per BOE, and increased 16% between the respective first quarters, primarily due to capital spending and increased costs. We allocated approximately $36.1 million of the $41.7 million preliminary adjusted purchase price of the Seabreeze acquisition to unevaluated properties to reflect the significant potential probable reserves that we considered to be as part of the acquisition. As a result, the acquisition did not materially affect our overall DD&A rate, as the amount included in our full cost pool was at a cost per BOE relatively consistent with our overall DD&A rate. We did not book any incremental oil reserves related to our tertiary operations during the first quarter of 2007, which historically have had a lower finding and development cost than our overall company average. Although we have seen some production response at Soso and Martinville Fields during the first quarter of 2007, based on the limited response thus far, we considered it premature to book any significant reserves to these fields. We expect that we may be able to book reserves associated with these fields in the second quarter. We continually evaluate the performance of our other 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 rate for our CO₂ and other general corporate fixed assets increased in the first quarter of 2007 as compared to the rate in the comparable quarter in 2006 as a result of the additional cost incurred drilling CO₂wells during the past year, putting the Free State CO₂ pipeline into service late in the first quarter of 2006, and higher associated future development costs, partially offset by an increase in CO₂reserves from 4.6 Tcf as of December 31, 2005, to 5.5 Tcf as of December 31, 2006 (100% working interest basis before amounts attributable to Genesis volumetric production payments).

26

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

	Three Months Ended
	March 31,
Amounts in thousands, except per BOE amounts and tax rates	2007			2006
Current income tax expense	$	1,618		$	9,786
Deferred income tax provision		9,014			18,184
Total income tax provision	$	10,632		$	27,970
Average income tax expense per BOE	$	3.08		$	8.77
Effective tax rate		39.0	%		39.0	%

     Our income tax provision for the first quarter of 2007 and 2006 was based on an estimated statutory tax rate of 39%. In both periods, the current income tax expense represents our anticipated alternative minimum cash taxes that we cannot offset with enhanced oil recovery credits. As of December 31, 2006, we had an estimated $41.9 million of enhanced oil recovery credits to carry forward that we can utilize to reduce our current income taxes during 2007. We have not earned any additional credits since 2005 due to the high oil prices, which completely phased out our ability to earn any additional credits.

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	2007			2006
Oil and natural gas revenues	$	49.06		$	55.01
Gain (loss) on settlements of derivative contracts		2.39			(0.24	)
Lease operating expenses		(14.66	)		(11.34	)
Production taxes and marketing expenses		(2.96	)		(2.53	)
Production netback		33.83			40.90
Non-tertiary CO2 operating margin		0.69			0.42
General and administrative expenses		(3.32	)		(3.09	)
Net cash interest expense		(1.18	)		(2.07	)
Current income taxes and other		0.22			(2.36	)
Changes in assets and liabilities relating to operations		(3.16	)		(1.67	)
Cash flow from operations		27.08			32.13
DD&A		(11.90	)		(10.26	)
Deferred income taxes		(2.61	)		(5.70	)
Non-cash derivative adjustments		(10.20	)		(3.40	)
Changes in assets and liabilities and other non-cash items		2.45			0.95
Net income	$	4.82		$	13.72

Market Risk Management

Debt

     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. The following table presents the carrying and fair values of our debt, along with average interest rates. We had $230 million of bank debt outstanding as of March 31, 2007 and $134 million at December 31, 2006. Approximately $150 million of the bank debt as of March 31, 2007

27

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

was repaid with proceeds from subordinated debt issued on April 3, 2007 under the December 2005 indenture governing our already outstanding subordinated debt due 2015 (see “Overview – April 2007 Debt Issuance”). The fair value of the subordinated debt is based on quoted market prices. None of our debt has any triggers or covenants regarding our debt ratings with rating agencies.

	Expected Maturity Dates		Carrying		Fair
Amounts in thousands	2007 - 2011		Value		Value
Variable rate debt:
Bank debt (matures September 2011) (The weighted average interest rate at March 31, 2007 was 6.3%)	$	230,000	$	230,000	$	230,000
Fixed rate debt:
7.5% subordinated debt due 2013, net of discount (The interest rate on the subordinated debt is a fixed rate of 7.5%)		—		223,834		226,688
7.5% subordinated debt, due 2015 (The interest rate on the subordinated debt is a fixed rate of 7.5%)		—		150,000		151,320

Oil and Gas Derivative Contracts

     From time to time, we enter into various oil and 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. Historically, we hedged up to 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt. Since 2005 and beyond, we have entered into fewer derivative contracts, primarily because of our strong financial position resulting from our lower levels of debt relative to our cash flow from operations. We did make an exception in late 2006 when we swapped 80% to 90% of our forecasted 2007 natural gas production at a weighted average price of $7.96 per Mcf. We did this to protect our 2007 projected cash flow, primarily because we currently plan to spend $200 million to $250 million more than we expect to generate in cash flow from operations (see “Capital Resources and Liquidity”) and we did not want to be exposed to the risk of lower natural gas prices.

     When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted proved production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. As of March 31, 2007, we had derivative contracts in place related to our $250 million acquisition that closed on January 31, 2006, on which we entered into contracts to cover 100% of the first three years estimated proved producing production at the time we signed the purchase and sale agreement. While these derivative contracts related to the acquisition represent approximately 7% of our estimated 2007 production, they are intended to help protect our acquisition economics related to the first three years of production from the proved producing reserves that we acquired. These swaps cover 2,000 Bbls/d for 2007 at a price of $58.93 per Bbl; and 2,000 Bbls/d for 2008 at a price of $57.34 per Bbl.

     At March 31, 2007, our derivative contracts were recorded at their fair value, which was a net liability of approximately $19.4 million, a decrease of approximately $35.1 million from the $15.7 million fair value asset recorded as of December 31, 2006. This change is the result of a decrease in the fair market value of our hedges due to an increase in oil and natural gas commodity futures prices between December 31, 2006 and March 31, 2007.

     Based on NYMEX crude oil futures prices at March 31, 2007, we would expect to make future cash payments of $14.6 million on our oil commodity hedges. If oil futures prices were to decline by 10%, the amount we would expect to pay under our oil commodity hedges would decrease to $5.7 million, and if futures prices were to increase by 10% we would expect to pay $23.5 million. Based on NYMEX natural gas futures prices at March 31, 2007, we would expect to make future cash payments of $5.4 million on our natural gas commodity hedges. If natural gas futures prices were to decline by 10%, we would expect to receive future cash payments of $11.6 million and if future prices were to increase by 10% we would expect to pay $22.4 million.

28

DENBURY RESOURCES INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Rate Lock Contracts

     In January 2007, we entered into interest rate lock contracts to remove our exposure to possible interest rate fluctuations related to our commitment to the sale-leaseback financing of certain equipment for CO₂ recycling facilities at our tertiary oil fields. The interest rate lock contracts cover equipment currently being constructed that we have committed to finance with Bank of America Leasing & Capital LLC. This equipment has two estimated completion dates, one during the fourth quarter of 2007 and one during mid-year 2008, with a total estimated cost of approximately $15 million and $24 million, respectively. We are applying hedge accounting to these contracts as provided under SFAS No. 133.

     At March 31, 2007, the interest rate locks were recorded at their fair value, which was a liability of approximately $0.8 million. If the 5-year Semi-Annual Swap Rate were to increase or decrease 50-basis points, we would expect the fair value liability to change by approximately $0.9 million, with the increase in rates being a benefit to us and a decrease in rates being a liability to us.

Critical Accounting Policies

     For a discussion of our critical accounting policies, which are related to property, plant and equipment, depletion and depreciation, oil and natural gas reserves, asset retirement obligations, income taxes and hedging activities, and 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, 2006.

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, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, cost savings, production rates and volumes or forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values, potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, future capital expenditures and overall economics and other variables surrounding our tertiary 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 the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas, inaccurate cost estimates, fluctuations in the prices of goods and services, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital or its availability, general economic conditions, competition and government regulations, unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or which are otherwise discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings and public statements.

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DENBURY RESOURCES INC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

     The information required by Item 3 is set forth under “Market Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 4. Controls and Procedures

     We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosure.

     There have been no significant changes in internal controls over financial reporting during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, Denbury’s internal controls over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

     Information with respect to this item has been incorporated by reference from our Form 10-K for the year ended December 31, 2006. There have been no material developments in such legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

     Information with respect to risk factors has been incorporated by reference from Item 1.A. of our Form 10-K for the year ended December 31, 2006. 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

     None

Item 3. Defaults Upon Senior Securities

     None.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

Item 5. Other Information

     None.

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DENBURY RESOURCES INC.

Item 6. Exhibits

Exhibits:
10*	First Amendment to 6th Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, Denbury Resources Inc., as Parent Guarantor, JPMorgan Chase Bank, N.A. as Administrative Agent, and certain other financial institutions effective as of March 31, 2007.
10(a)*	Amendment for Increased Commitment from $250 million to $350 million to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, and JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other financial institutions dated as of March 31, 2007.
31(a)*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

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DENBURY RESOURCES INC.

SIGNATURES

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

DENBURY RESOURCES INC. (Registrant)
By:	/s/ Phil Rykhoek
	Phil Rykhoek
	Sr. Vice President and Chief Financial Officer
By:	/s/ Mark C. Allen
	Mark C. Allen
	Vice President and Chief Accounting Officer

Date: May 4, 2007

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