Denbury 10Q 2006 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, 2006


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, 2006

Common Stock, $.001 par value		119,055,659

INDEX


		Page
Part I. Financial Information

Item 1. Financial Statements

Unaudited Condensed Consolidated Balance Sheets at March 31, 2006 and December 31, 2005		3

Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2006 and 2005		4

Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2006 and 2005		5

Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three Months Ended March 31, 2006 and 2005		6

Notes to Unaudited Condensed Consolidated Financial Statements		7-18

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19-31

Item 3. Quantitative and Qualitative Disclosures about Market Risk		32

Item 4. Controls and Procedures		32

Part II. Other Information

Item 1. Legal Proceedings		32

Item 1A. Risk Factors		32

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 3. Defaults Upon Senior Securities		34

Item 4. Submission of Matters to a Vote of Security Holders		34

Item 5. Other Information		34

Item 6. Exhibits		34

Signatures		35
Amendment to the Fifth Amended and Restated Credit Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares)


	March 31,			December 31,
	2006			2005
Assets
Current assets
Cash and cash equivalents	$	29,984		$	165,089
Accrued production receivable		65,833			65,611
Related party receivable — Genesis		933			1,312
Trade and other receivables		21,629			25,887
Deferred tax asset		38,131			41,284
Other current assets		10,000			—

Total current assets		166,510			299,183


Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		1,922,223			1,669,579
Unevaluated		172,871			46,597
CO₂ properties and equipment		221,070			210,046
Other		36,751			34,647
Less accumulated depletion and depreciation		(837,039	)		(804,899	)

Net property and equipment		1,515,876			1,155,970

Investment in Genesis		10,845			10,829
Deposits on property acquisitions		126			26,425
Other assets		12,708			12,662

Total assets	$	1,706,065		$	1,505,069

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	110,487		$	104,840
Oil and gas production payable		46,688			41,821
Derivative liabilities		7,628			2,759
Deferred revenue — Genesis		4,070			4,070
Short-term capital lease obligations — Genesis		588			574

Total current liabilities		169,461			154,064


Long-term liabilities
Capital lease obligations — Genesis		5,717			5,870
Long-term debt		473,640			373,591
Asset retirement obligations		32,905			25,297
Derivative liabilities		12,618			6,624
Deferred revenue — Genesis		32,082			33,023
Deferred tax liability		185,788			170,758
Other		2,620			2,180

Total long-term liabilities		745,370			617,343


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; 115,841,380 and 115,038,531 shares issued at March 31, 2006 and December 31, 2005, respectively		116			115
Paid-in capital in excess of par		456,626			443,283
Retained earnings		339,353			295,575
Treasury stock, at cost, 311,388 and 340,337 shares at March 31, 2006 and December 31, 2005, respectively		(4,861	)		(5,311	)

Total stockholders’ equity		791,234			733,662

Total liabilities and stockholders’ equity	$	1,706,065		$	1,505,069

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Three Months Ended
	March 31,
	2006		2005
Revenues
Oil, natural gas and related product sales:
Unrelated parties	$	174,094	$	110,597
Related party — Genesis		1,449		419
CO₂ sales and transportation fees		1,988		1,730
Interest income and other		1,375		616

Total revenues		178,906		113,362


Expenses
Lease operating expenses		36,172		22,962
Production taxes and marketing expenses		7,088		5,190
Transportation expense — Genesis		999		936
CO₂ operating expenses		645		346
General and administrative		9,867		6,495
Interest, net of interest capitalized of $274 and $262, respectively		8,254		4,476
Depletion, depreciation, and accretion		32,743		21,528
Commodity derivative expense		11,630		7,821

Total expenses		107,398		69,754


Equity in net income of Genesis		240		287


Income before income taxes		71,748		43,895

Income tax provision
Current income taxes		9,786		5,282
Deferred income taxes		18,184		8,546

Net income	$	43,778	$	30,067


Net income per common share — basic	$	0.39	$	0.27

Net income per common share — diluted	$	0.37	$	0.26

Weighted average common shares outstanding
Basic		113,151		110,919
Diluted		119,925		117,207

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Three Months Ended
	March 31,
	2006			2005
Cash flow from operating activities:
Net income	$	43,778		$	30,067
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and accretion		32,743			21,528
Non-cash hedging adjustments		10,862			6,722
Deferred income taxes		18,184			8,546
Deferred revenue — Genesis		(940	)		(622	)
Stock-based compensation		2,972			1,028
Current income tax benefit from stock options		—			2,080
Amortization of debt issue costs and other		250			62
Changes in assets and liabilities:
Accrued production receivable		157			(5,919	)
Trade and other receivables		4,258			(3,088	)
Other assets		(10,132	)		130
Accounts payable and accrued liabilities		(4,741	)		7,244
Oil and gas production payable		4,866			(683	)
Other liabilities		255			(466	)

Net cash provided by operating activities		102,512			66,629


Cash flow used for investing activities:
Oil and natural gas expenditures		(118,599	)		(57,195	)
Acquisitions of oil and gas properties		(252,410	)		(30,781	)
Increase in accrual for capital expenditures		10,028			11,239
Acquisitions of CO₂ assets and capital expenditures		(11,024	)		(27,963	)
Net purchases of other assets		(1,940	)		(1,930	)
Proceeds from sales of oil and gas properties and equipment		—			(18	)
Deposits on acquisitions		26,299			4,507
Sales of short-term investments		—			42,575
Increase in restricted cash		(38	)		(48	)

Net cash used for investing activities		(347,684	)		(59,614	)


Cash flow from financing activities:
Bank repayments		—			(14,000	)
Bank borrowings		100,000			14,000
Costs of debt financing		(88	)		—
Payments on capital lease obligations — Genesis		(138	)		(125	)
Issuance of common stock		4,465			4,361
Current income tax benefit from stock options		5,835			—
Purchase of treasury stock		(7	)		(1,548	)

Net cash provided by financing activities		110,067			2,688


Net increase (decrease) in cash and cash equivalents		(135,105	)		9,703

Cash and cash equivalents at beginning of period		165,089			33,039

Cash and cash equivalents at end of period	$	29,984		$	42,742

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	1,125		$	259
Cash paid during the period for income taxes		5,500			—

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF

COMPREHENSIVE OPERATIONS

(In thousands)


	Three Months Ended
	March 31,
	2006		2005
Net income	$	43,778	$	30,067
Other comprehensive income, net of income tax:
Reclassification adjustments related to settlements of derivative contracts, net of tax of $689		—		1,125
Unrealized gain on securities available for sale		—		2

Comprehensive income	$	43,778	$	31,194

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2005. 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, 2006 and the consolidated results of its operations and cash flows for the three month periods ended March 31, 2006 and 2005. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Stock Split

On October 19, 2005, stockholders of Denbury Resources Inc. approved an amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 100,000,000 shares to 250,000,000 shares and to split our common stock on a 2-for-1 basis. Stockholders of record on October 31, 2005, received one additional share of Denbury common stock for each share of common stock held at that time. Information pertaining to shares and earnings per share has been retroactively adjusted in the accompanying financial statements and related notes thereto to reflect the stock split.

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 and any other convertible securities outstanding. For the three month periods ended March 31, 2006 and 2005, there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three month periods ended March 31, 2006 and 2005.


	Three Months Ended
	March 31,
	2006		2005
(shares in thousands)
Weighted average common shares — basic		113,151		110,919

Potentially dilutive securities:
Stock options and stock appreciation rights		5,880		5,654
Restricted stock		894		634

Weighted average common shares — diluted		119,925		117,207

The weighted average common shares – basic amount excludes 2,047,576 shares and 2,320,000 shares in 2006 and 2005, respectively, of non-vested restricted stock that is subject to future vesting over time. As these restricted shares

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

For the three months ended March 31, 2005, common stock options to purchase approximately 35,000 shares of common stock were outstanding but excluded from the diluted net income per common share calculations, 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 calculations. There were no anti-dilutive options outstanding for the three months ended March 31, 2006.

Stock-based Compensation

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share Based Payment,” which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based compensation to employees, including grants of employee stock options, to be recognized in our consolidated financial statements based on estimated fair value.

We adopted SFAS No. 123(R) on January 1, 2006, using the modified prospective application method described in the statement. Under the modified prospective method, effective January 1, 2006, we began to recognize compensation expense for the unvested portion of awards outstanding as of December 31, 2005 over the remaining service periods, and for new awards granted or modified after January 1, 2006. See Note 4 for further discussion regarding our stock incentive plans.

2. ACQUISITIONS

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. We expect to begin our initial tertiary development work at Tinsley Field during 2006 with more significant work during 2007. The timing of tertiary development at Citronelle Field is uncertain as we will need to build a 60- to 70-mile pipeline extension of our line to East Mississippi before flooding can commence, and South Cypress Creek will probably be flooded following our initial development of our other East Mississippi properties.

The preliminary adjusted purchase price is approximately $248 million, after adjusting for interim net cash flow between the effective date and closing date of the acquisition and minor purchase price adjustments. The $248 million 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 sale agreement. The preliminary purchase price of $248 million 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, probable and possible reserves acquired. Based on this analysis, $125 million was assigned to proved properties and $123 million 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 currently estimate that this development will take place over the next two to five years. The acquisition was funded with the proceeds of $150 million of senior subordinated notes issued in December 2005 and $100 million of bank financing under the Company’s existing credit facility (repaid in late April 2006).

The operating results of the acquired properties were included in our financial statements beginning in February 2006. 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 2006 and 2005.

On January 11, 2006, we increased the commitment on our bank credit line from $100 million to $150 million to allow additional availability under our credit line after closing the $248 million January 2006 acquisition discussed above. We also increased our bank borrowing base from $200 million to $300 million as of April 1, 2006 to provide further flexibility. The bank credit line was repaid in late April 2006 with the proceeds from the $125 million equity offering in April 2006 (See Note 8).

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3. ASSET RETIREMENT OBLIGATIONS

In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil and natural gas wells, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation 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, 2006.


	Three Months Ended
	March 31, 2006
	(in thousands)
Beginning asset retirement obligation, as of 12/31/2005	$	27,088
Liabilities incurred during period		7,434
Revisions in estimated cash flows		109
Liabilities settled during period		(227	)
Accretion expense		571

Ending asset retirement obligation, as of 3/31/2006	$	34,975

At March 31, 2006, $2.1 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 three oil properties we acquired during January 2006. 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 $6.7 million at March 31, 2006, and $6.7 million at December 31, 2005 and are included in “Other assets” in our Condensed Consolidated Balance Sheets.

4. STOCK INCENTIVE PLANS

Denbury has two stock incentive plans. The first plan has been in existence since 1995 (the ��1995 Plan”) and expired in August 2005 (although options granted under the 1995 Plan prior to that time can remain outstanding for up to 10 years). The 1995 plan only provided for the issuance of stock options and in January 2005, we issued stock options under the 1995 Plan that utilized substantially all of the remaining shares. The second plan, the 2004 Omnibus Stock and Incentive Plan (the “2004 Plan”) has a 10-year term and was approved by the shareholders in May 2004. Awards covering a total of 5.0 million shares of common stock are authorized for issuance pursuant to the 2004 Plan, of which awards covering no more than 2,750,000 shares may be issued in the form of restricted stock or performance vesting awards. At March 31, 2006, a total of 1,244,263 shares were available for future issuance of awards, of which only 391,724 shares may be in the form of restricted stock or performance vesting awards. The 2004 Plan provides for the issuance of incentive and non-qualified stock options, restricted share awards and stock appreciation rights (“SARS”) settled in stock that may be issued to officers, employees, directors and consultants.

Denbury has historically granted incentive and non-qualified stock options to its employees. Effective January 1, 2006, we have completely replaced the use of stock options with SARS as SARS are less dilutive to our shareholders while providing an employee with essentially the same economic benefits as stock options. The stock options and SARS (collectively “Options”) generally become exercisable over a four-year vesting period with the specific terms of vesting determined by the Board of Directors at the time of grant. The Options expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment or permanent disability or one year after the death of the optionee. The Options are granted at the fair market value at the time of grant, which is generally defined in the 2004 Plan as the closing price on the date of grant. The plan is administered by the Compensation Committee of Denbury’s Board of Directors.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During August 2004 through January 2005, the Board of Directors, based on a recommendation by the Board’s Compensation Committee, awarded the officers of Denbury a total of 2,200,000 shares of restricted stock and the independent directors of Denbury a total of 120,000 shares of restricted stock, all granted under the 2004 Plan. The holders of these shares have all of the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of the certificates until certain requirements are met. With respect to the 2,200,000 shares of restricted stock granted to officers of Denbury, the vesting restrictions on those shares are as follows: i) 65% of the awards vest 20% per year over five years and, ii) 35% of the awards vest upon retirement, as defined in the 2004 Plan. With respect to the 65% of the awards that vest over five years, on each annual vesting date, 66-2/3% of the vested shares may be delivered to the holder with the remaining 33-1/3% retained and held in escrow until the holder’s separation from the Company. With respect to the 120,000 restricted shares issued to Denbury’s independent board members, the shares vest 20% per year over five years. For these shares, on each annual vesting date, 40% of such vested shares may be delivered to the holder with the remaining 60% retained and held in escrow until the holder’s separation from the Company. In January 2006, a total of 38,276 shares of restricted stock were granted to officers and certain members of our management group. These shares “cliff” vest four years from the date of grant.

The compensation expense that has been charged against income for stock-based compensation was $3.0 million for the three months ended March 31, 2006. Part of this expense, $0.4 million, was included in “Lease operating expenses” for the stock compensation expense associated with our field employees and the remaining $2.6 million recognized in “General and administrative expenses” in the Condensed Consolidated Income Statement. The total income tax benefit recognized in the income statement for the share-based compensation arrangements was $0.2 million for the three months ended March 31, 2006. Share-based compensation capitalized as part of “Oil and Natural Gas Properties” was $0.5 million for the three months ended March 31, 2006.

Prior to 2006, we accounted for this stock-based compensation utilizing the recognition and measurement principles of Accounting Principles Board Opinion 25 (APB 25), “Accounting for Stock Issued to Employees,” and its related interpretations. Under these principles, no compensation expense for stock options is reflected in net income as long as the stock options have an exercise price equal to the quoted market price of the underlying common stock on the date of grant. For restricted stock grants, we recognize compensation expense equal to the intrinsic value of the stock on the date of grant over the applicable vesting periods. The following table illustrates the effect on net income and net income per common share if we had applied the fair value recognition and measurement provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, in accounting for our stock-based compensation.


	Three Months Ended
	March 31, 2005
Net income: (thousands)
Net income, as reported	$	30,067
Add: stock-based compensation included in reported net income, net of related tax effects		627
Less: stock-based compensation expense applying fair value based method, net of related tax effects		1,544

Pro-forma net income	$	29,150


Net income per common share
As reported:
Basic	$	0.27
Diluted		0.26
Pro forma:
Basic	$	0.26
Diluted		0.25

Prior to the adoption of SFAS No. 123(R) on January 1, 2006, we did not capitalize any stock-based compensation cost in our SFAS No. 123 pro forma net income. As a result no stock-based compensation expense is capitalized in the table above. Beginning in 2006, an appropriate portion of stock-based compensation associated with our employees involved

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

in our exploration and drilling activities has been capitalized as part of our “Oil and Natural Gas Properties” in our Condensed Consolidated Balance Sheet. The effect of applying SFAS No. 123(R) during the three months ended March 31, 2006 was to decrease income before income taxes by approximately $2.0 million, decrease net income by approximately $1.8 million and decrease both basic and diluted earnings per share by $0.02. Additionally, cash flow from operations was lower and cash flow from financing activities was higher by approximately $5.8 million associated with the tax benefits in excess of recognized compensation expenses that are now required to be reported as a financing cash flow.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model using the assumptions noted in the following table. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected life of options granted was derived from examination of our historical option grants and subsequent exercises. The contractual terms (4-year cliff vesting and 4-year graded vesting) are evaluated separately for the expected life, as the exercise behavior for each is different. Expected volatilities are based on the historical volatility of our stock. Implied volatility was not used in this analysis as our tradable call option terms are short and the trading volume is low. Our dividend yield is zero, as Denbury does not pay a dividend.


	Three months ended			Year ended
	March 31, 2006			December 31, 2005
Weighted average fair value of options granted	$	12.54		$	6.94
Risk free interest rate		4.40	%		3.80	%
Expected life		4.9 to 6.9 years			5 years
Expected volatility		42.9	%		42.6	%
Dividend yield		—			—

The following is a summary of our stock option and SAR activity for the three months ended March 31, 2006 and the year ended December 31, 2005:


	Three Months Ended					Year Ended
	March 31, 2006					December 31, 2005
				Weighted					Weighted
	Number			Average		Number			Average
	of Options			Price		of Options			Price
Outstanding at beginning of period		9,406,072		$	8.07		8,880,314		$	5.25
Granted		365,249			25.09		2,483,254			16.29
Exercised		(765,401	)		4.77		(1,797,146	)		5.37
Forfeited		(149,714	)		9.61		(160,350	)		8.86

Outstanding at end of period		8,856,206			9.04		9,406,072			8.07


Exercisable at end of period		3,139,132		$	4.39		2,509,635		$	4.50

The total intrinsic value of options exercised during the three months ended March 31, 2006 and the year ended December 31, 2005 was approximately $17.4 million and $24.8 million, respectively. The aggregate intrinsic value of stock options and SARs outstanding at March 31, 2006 was approximately $200.4 million and these options and SARs have a weighted-average remaining contractual life of 6.7 years. The aggregate intrinsic value of stock options exercisable at March 31, 2006 was approximately $85.6 million and these options and SARs have a weighted-average remaining contractual life of 4.2 years.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A summary of the status of our nonvested options as of March 31, 2006, and the changes during the three months ended March 31, 2006, is presented below:


				Weighted-Average
				Grant-Date
Nonvested Stock Options	Shares			Fair Value
Nonvested at January 1, 2006		6,896,437		$	4.25
Granted		365,249			12.54
Vested		(1,395,486	)		2.34
Forfeited		(149,126	)		4.47

Nonvested at March 31, 2006		5,717,074			5.24

As of March 31, 2006, there was $16.4 million of total compensation cost to be recognized in future periods related to nonvested stock option share-based compensation arrangements. The cost is expected to be recognized over a weighted-average period of 1.3 years. Cash received from the option exercises under share-based payment arrangements for the three months ended March 31, 2006 and year ended December 31, 2005 was $3.6 million and $9.7 million, respectively. The actual tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $15.6 million for the three months ended March 31, 2006 and $22.0 million for the year ended December 31, 2005.

Upon issuance of the 2,358,276 shares of restricted stock pursuant to the 2004 Plan, we recorded deferred compensation expense of $24.5 million, the market value of the shares on the grant dates, as a reduction to shareholders’ equity. This expense will be amortized over the applicable five-year, four-year, or retirement date vesting periods. As of March 31, 2006, there was $17.6 million of unrecognized compensation expense related to nonvested restricted stock grants. The unrecognized compensation cost is expected to be recognized over a weighted-average period of 3.2 years.

A summary of the status of our non-vested restricted stock grants as of March 31, 2006, and the changes during the three months ended March 31, 2006, is presented below:


				Weighted-Average
				Grant-Date
Nonvested Restricted Stock Grants	Shares			Fair Value
Nonvested at January 1, 2006		2,014,000		$	10.15
Granted		38,276			24.58
Vested		(4,700	)		15.20
Forfeited		—			—

Nonvested at March 31, 2006		2,047,576			10.41

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, 2006 and 2005 was $240,000 and $287,000, respectively. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which as of March 31, 2006 was $2.6 million, plus $10.7 million in outstanding letters of credit. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 2006 and 2005, we expensed $1.0 million and $0.9 million, respectively, for these transportation services. Denbury received other miscellaneous payments from Genesis for the three months ended March 31, 2006 and 2005, including $30,000 in each period of director fees for certain executive officers of Denbury that are board members of Genesis, and $220,000 and $130,000, respectively, in pro rata dividend distributions from Genesis.

Transportation Leases

In late 2004 and early 2005, we entered into pipeline transportation agreements with Genesis to transport in its pipelines our crude oil from Olive, Brookhaven, and McComb Fields in Southwest Mississippi to Genesis’ main crude oil pipeline in order to improve our ability to market our crude oil, and to transport CO₂ from our main CO₂pipeline to Brookhaven Field for our tertiary operations. As part of these arrangements, we entered into three transportation agreements. The first agreement, entered into in November 2004, was to transport crude oil from Olive Field. This agreement is for 10 years and has a minimum payment of approximately $18,000 per month. In December 2004, we entered into a second transportation agreement, to transport CO₂to Brookhaven Field in Southwest Mississippi. This agreement is for an eight-year period and has minimum payments of approximately $49,000 per month. In January 2005, we entered into a third transportation agreement, to transport crude oil from Brookhaven Field. This agreement is for 10 years and has a minimum payment of approximately $32,000 per month. The minimum monthly payment in each agreement will increase for any volumes transported in excess of the stated monthly volume in the contract. Genesis will operate and maintain these pipelines at its own expense.

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, 2006, we had $6.3 million of capital lease obligations related to these agreements recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $588,000 was current. At December 31, 2005, we had $6.4 million of capital lease obligations related to these agreements recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $574,000 was current.

CO₂ Volumetric Production Payments

In November 2003, we sold 167.5 Bcf of CO₂ to Genesis for $24.9 million ($23.9 million as adjusted for interim cash flows from the September 1, 2003 effective date and for transaction costs) under a volumetric production payment (“VPP”), and assigned to Genesis three of our existing long-term commercial CO₂ supply agreements with our industrial customers. These industrial contracts represented approximately 60% of our then current industrial CO₂ sales volumes. Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d of CO₂through 2009, 43.0 MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term.

On August 26, 2004, we closed on another transaction with Genesis, selling to them a 33.0 Bcf volumetric production payment (“VPPII”) of CO₂ for $4.8 million ($4.6 million as adjusted for interim cash flows from the July 1 effective date and for transaction costs) along with a related long-term supply agreement with an industrial customer. Pursuant to the VPPII, Genesis may take up to 9 MMcf/d of CO₂ to the end of the contract term.

In October 2005, we sold a third CO₂ volumetric production payment (“VPP III”) to Genesis. Under the VPP III, we sold 80.0 Bcf of CO₂ for $14.7 million ($14.4 million as adjusted for interim cash flows from the September 1 effective date and for transaction costs), and assigned to Genesis two of our existing long-term commercial CO₂ supply agreements with our industrial customers. Pursuant to the VPP III, Genesis may take up to 27.4 MMcf/d to the end of the contract term.

We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and will recognize such revenue as CO₂ is delivered during the term of the three volumetric production payments. At March 31, 2006 and December 31, 2005, $36.2 million and $37.1 million, respectively, was recorded as deferred revenue of which

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

$4.1 million was included in current liabilities at March 31, 2006 and December 31, 2005. During the three months ended March 31, 2006 and 2005, we recognized deferred revenue of $940,000 and $622,000, respectively, for deliveries under these volumetric production payments. We provide Genesis with certain processing and transportation services in connection with these agreements for a fee of approximately $0.17 per Mcf of CO₂ delivered to their industrial customers, which resulted in our receiving $1.0 million and $717,000 in revenue for the three months ended March 31, 2006 and 2005, respectively.

Summarized financial information of Genesis Energy, L.P. (amounts in thousands):


	Three Months Ended
	March 31,
	2006		2005
Revenues	$	263,602	$	256,600
Cost of sales		256,758		251,744
Other expenses		4,253		2,086

Net income	$	2,591	$	2,770


	March 31,		December 31,
	2006		2005
Current assets	$	98,386	$	90,449
Non-current assets		89,610		91,328

Total assets	$	187,996	$	181,777


Current liabilities	$	96,021	$	92,611
Non-current liabilities		3,564		955
Partners’ capital		88,411		88,211

Total liabilities and partners’ capital	$	187,996	$	181,777

6. DERIVATIVE CONTRACTS

Effective January 1, 2005, we elected to discontinue hedge accounting for our oil and natural gas derivative contracts and accordingly de-designated our derivative instruments from hedge accounting treatment. As a result of this change, we began accounting for our oil and natural gas derivative contracts as speculative contracts in the first quarter of 2005. As speculative contracts, the changes in the fair value of these instruments are recognized in income in the period of change.

We enter into various financial contracts to economically hedge 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 historically consisted of price floors, collars and fixed price swaps. Historically, we have generally attempted to hedge between 50% and 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover a majority of our budgeted exploration and development expenditures without incurring significant debt, although our hedging percentage may vary relative to our debt levels. Since 2005, we have entered into fewer derivative contracts, primarily because of our strong financial position resulted from our lower levels of debt relative to our cash flow from operations. When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment, including our doing so in connection with our $248 million acquisition in the first quarter of 2006. All of the mark-to-market valuations used for our financial derivatives are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk through established internal control procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


	Three Months Ended March 31,
(In Thousands)	2006		2005
Settlements of derivative contracts not designated as hedges — Oil	$	768	$	—
Settlements of derivative contracts not designated as hedges — Gas		—		1,099
Reclassification of accumulated other comprehensive income balance and adjustments to fair value associated with contracts no longer designated as hedges		10,862		6,722

Commodity derivative expense	$	11,630	$	7,821

Derivative Oil Contracts at March 31, 2006


					Fair Value at
	NYMEX Contract Prices Per Bbl				March 31, 2006
Type of Contract and Period	Bbls/d		Swap Price		(In Thousands)
Swap Contracts
April 2006 — Dec. 2006		2,200	$	59.65	$	(5,764	)
Jan. 2007 — Dec. 2007		2,000		58.93		(7,264	)
Jan. 2008 — Dec. 2008		2,000		57.34		(7,218	)

At March 31, 2006, our derivative contracts were recorded at their fair value, which was a net liability of $20.2 million.

7. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On December 29, 2003, we amended the indenture for our 7.5% Senior Subordinated Notes due 2013 to reflect our new holding company organizational structure. As part of this restructuring our indenture was amended so that both Denbury Resources Inc. and Denbury Onshore, LLC became co-obligors of our subordinated debt. Prior to this restructure, Denbury Resources Inc. was the sole obligor. Our subordinated debt is fully and unconditionally guaranteed by Denbury Resources Inc.’s significant subsidiaries other than minor subsidiaries. The results of our equity interest in Genesis is reflected through the equity method by one of our significant 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 significant subsidiaries:

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Balance Sheets


(In Thousands)	March 31, 2006
	Denbury		Denbury
	Resources Inc.		Onshore, LLC							Denbury
	(Parent and		(Issuer and		Guarantor					Resources Inc.
	Co-obligor)		Co-obligor)		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	236,274	$	163,530	$	3,943	$	(237,237	)	$	166,510
Property and equipment		—		1,515,835		41		—			1,515,876
Investment in subsidiaries (equity method)		550,721		—		549,659		(1,089,535	)		10,845
Other assets		154,239		10,917		160		(152,482	)		12,834

Total assets	$	941,234	$	1,690,282	$	553,803	$	(1,479,254	)	$	1,706,065


Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	403,796	$	2,902	$	(237,237	)	$	169,461
Long-term liabilities		150,000		747,672		180		(152,482	)		745,370
Stockholders’ equity		791,234		538,814		550,721		(1,089,535	)		791,234

Total liabilities and stockholders’ equity	$	941,234	$	1,690,282	$	553,803	$	(1,479,254	)	$	1,706,065


(In Thousands)	December 31, 2005
	Denbury		Denbury
	Resources Inc.		Onshore, LLC							Denbury
	(Parent and		(Issuer and		Guarantor					Resources Inc.
	Co-obligor)		Co-obligor)		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	222,858	$	297,575	$	2,577	$	(223,827	)	$	299,183
Property and equipment		—		1,155,923		47		—			1,155,970
Investment in subsidiaries (equity method)		506,862		—		505,540		(1,001,573	)		10,829
Other assets		154,288		37,120		169		(152,490	)		39,087

Total assets	$	884,008	$	1,490,618	$	508,333	$	(1,377,890	)	$	1,505,069


Liabilities and Stockholders’ Equity
Current liabilities	$	346	$	376,194	$	1,351	$	(223,827	)	$	154,064
Long-term liabilities		150,000		619,713		120		(152,490	)		617,343
Stockholders’ equity		733,662		494,711		506,862		(1,001,573	)		733,662

Total liabilities and stockholders’ equity	$	884,008	$	1,490,618	$	508,333	$	(1,377,890	)	$	1,505,069

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Operations


(In Thousands)	Three Months Ended March 31, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and		Guarantor						Resources Inc.
	Co-Obligor)			Co-Obligor)		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


(In Thousands)	Three Months Ended March 31, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and		Guarantor						Resources Inc.
	Co-Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	113,362	$	—		$	—		$	113,362
Expenses		41			69,486		227			—			69,754

Income before the following:		(41	)		43,876		(227	)		—			43,608
Equity in net earnings of subsidiaries		30,092			—		30,342			(60,147	)		287

Income before income taxes		30,051			43,876		30,115			(60,147	)		43,895
Income tax provision		(16	)		13,821		23			—			13,828

Net income	$	30,067		$	30,055	$	30,092		$	(60,147	)	$	30,067

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Cash Flows


(In Thousands)	Three Months Ended March 31, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC							Denbury
	(Parent and			(Issuer and			Guarantor				Resources Inc.
	Co-Obligor)			Co-Obligor)			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


(In Thousands)	Three Months Ended March 31, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC							Denbury
	(Parent and			(Issuer and			Guarantor				Resources Inc.
	Co-Obligor)			Co-Obligor)			Subsidiaries		Eliminations		Consolidated
Cash flow from operations	$	(2,813	)	$	69,316		$	126	$	—	$	66,629
Cash flow from investing activities		—			(59,614	)		—		—		(59,614	)
Cash flow from financing activities		2,813			(125	)		—		—		2,688

Net increase in cash		—			9,577			126		—		9,703
Cash, beginning of period		1			32,881			157		—		33,039

Cash, end of period	$	1		$	42,458		$	283	$	—	$	42,742

8. SUBSEQUENT EVENT

On April 25, 2006, we closed on the $125 million sale of 3,492,595 shares of common stock at $35.79 per share, net to us, in a public offering. We used the net proceeds from the offering to repay our current borrowings under our bank credit facility, which were $120 million as of April 25, 2006, the majority of which was incurred to partially fund our $248 million acquisition of three properties in January 2006. The underwriter has an option to purchase up to an additional $18.75 million of common stock (523,889 shares) at the same price through May 19, 2006 to cover over-allotments, if any.

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 our Form 10-K for the year ended December 31, 2005, 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 and 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, and in the Barnett Shale play near Fort Worth, 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 three primary field offices located in Houma, Louisiana; Laurel, Mississippi; and Cleburne, Texas.

Overview

Operating results.Earnings and cash flow from operations were at near-record levels for the first quarter of 2006, primarily as a result of high commodity prices. Near-record production levels also contributed to the strong earnings, assisted in part by the acquisition which closed January 31, 2006 which added approximately two months of production to the quarter, or 1,476 BOE/d, and a significant increase in Louisiana production over the prior quarter as some of our recent successful exploratory wells came on production. Partially offsetting the positive production and commodity prices was a $10.9 million ($6.6 million after tax) mark-to-market pre-tax charge to earnings as the rising oil prices reduced the value of the Company’s oil derivative contracts put in place for the January acquisition. Additionally, we booked an expense for certain of our stock compensation for the first time (mainly unvested stock options and stock appreciation rights), following the adoption of SFAS No. 123(R) as of January 1, 2006, which resulted in a non-cash charge of approximately $1.7 million to general and administrative expense, approximately $0.4 million to lease operating expense and approximately $0.4 million to capitalized oil and gas properties, representing an aggregate $2.5 million increase to stock compensation charges directly related to the adoption of SFAS No. 123(R). The net result was net income of $43.8 million during the first quarter of 2006 as compared to $30.1 million of net income during the first quarter of 2005. Last year’s first quarter 2005 net income included the effect of approximately $6.7 million ($4.6 million after tax) of mark-to-market and other non-cash charges related to derivative contracts in place at that time.

Cash payments on our commodity derivative contracts were slightly lower in the first quarter of 2006 than in the first quarter of 2005, as our derivative contracts represented less than 10% of our total production for both comparative periods (excluding price floors in 2005 which have no potential cash payment). Total cash payments on hedges were approximately $0.8 million in the first quarter of 2006 as compared to $1.1 million during the first quarter of 2005.

Most of our expenses increased on both an absolute and per BOE basis during the first quarter of 2006 due to (i) rising costs in the industry, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), (iii) the impact of adopting SFAS No. 123(R) previously discussed, (iv) higher debt levels following our $248 million acquisition in January, and (v) a higher effective income tax rate as a result of losing our ability to earn enhanced oil recovery tax credits during 2006 due to high oil prices. In addition to inflationary costs in our industry, we are experiencing more and more delays in obtaining goods and services. These industry trends have caused us to experience higher costs than originally forecasted and to periodically fall behind with regard to timing of planned activities. If these trends continue, we are likely to see continued rising costs, both for operating expenses and capital expenditures, as well as delays in achieving the production targets that we anticipate. See “Results of Operations” for a more thorough discussion of our operating results and “Market Risk Management” for more information regarding our hedging positions at March 31, 2006.

Overview of tertiary operations.Since we acquired our first carbon dioxide tertiary flood in Mississippi over six years ago, we have gradually increased our emphasis on these operations, so that approximately 50% of our 2006 capital budget is related to 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 CO₂ that we own drive the play. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the

DENBURY RESOURCES INC.

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

sections entitled “Overview” and “CO₂ Operations” contained in our 2005 Form 10-K for further information regarding these operations, their potential, and the ramifications of this change in focus.

Oil production from our tertiary operations increased to an average of 9,758 BOE/d in the first quarter of 2006, a 13% increase over the first quarter 2005 tertiary production level of 8,644 BOE/d and about the same as fourth quarter 2005 production levels. The tertiary oil production response has been slower than anticipated, particularly at McComb Field, primarily because we have not been able to inject CO₂ as fast as we originally planned. The correlation between CO₂ injections and oil production is similar to that at Little Creek Field, our most mature tertiary model, but since CO₂ injections have been behind forecast, so has oil production. Although we are still testing our theory, we believe that by raising the CO₂ injection pressure we may remedy this situation in the future, although it will take some time before it has any meaningful impact on our production rates. As such, we lowered our 2006 tertiary oil production target in late March from 13,000 BOE/d, to a range of between 11,750 BOE/d and 12,750 BOE/d.

Recent 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. We expect to begin our initial tertiary development work at Tinsley Field during 2006, with more extensive development planned for 2007. The timing of tertiary development at Citronelle Field is uncertain as we will need to build a 60-to-70 mile extension of our CO₂ pipeline to East Mississippi before flooding can commence, and South Cypress Creek will probably be flooded following our initial development of our other East Mississippi properties. The preliminary adjusted purchase price for these three properties was approximately $248 million, after adjusting for interim net cash flow and minor purchase price adjustments. The acquisition was funded with proceeds of the $150 million of senior subordinated notes issued in December 2005 and $100 million of bank financing under the Company’s existing credit facility. These three fields are currently producing approximately 2,200 BOE/d net to the acquired interests, and as of December 31, 2005 had proved reserves of approximately 14.4 million BOEs. We operate all three fields and own the majority of the working interests.

April 2006 Equity Offering.On April 25, 2006, we closed the $125 million sale of 3,492,595 shares of common stock at $35.79 per share, net to us in a public offering. We used the net proceeds from the offering to repay current borrowings under our bank credit facility, which were $120 million as of April 25, 2006, the majority of which was incurred to partially fund our $248 million acquisition of three properties in January 2006. The underwriter has an option to purchase up to an additional $18.75 million of common stock (523,889 shares) at the same price through May 19, 2006 to cover over-allotments, if any.

Capital Resources and Liquidity

Our current 2006 capital budget, excluding any potential acquisitions, is $494 million, which at commodity futures prices as of the end of April 2006, appears to be slightly more than our anticipated cash flow from operations. With our recent sale of equity and reduction in overall debt to $375 million, it is likely that we will increase our capital budget for 2006 by $25 to $50 million in order to compensate for rising costs and possibly to accelerate a portion of our 2007 expenditures. Due to the long lead time for certain items, we would like to order equipment earlier than we have historically and often these orders require an upfront deposit, thus potentially increasing our 2006 expenditures. Any incremental capital expenditures will, in effect, be funded by the recently closed equity offering. In addition, we continue to pursue acquisitions of old oil fields that could be future tertiary flood candidates. These possible acquisitions are difficult to forecast and the purchase price can vary widely depending on the level of existing production and conventional proved reserves. With the recently closed equity offering and our reduced debt levels, we are more comfortable pursuing these acquisitions, as it is our desire to maintain a strong financial position.

As of April 1, 2006, our bank borrowing base was increased from $200 million to $300 million in order to provide us with additional flexibility. It is our belief that we could increase this line even further if necessary. This increased borrowing base and our recently reduced debt level gives us tremendous flexibility with regard to our capital and acquisition program. As such, we do not anticipate having any liquidity issues in the foreseeable future. As of March 31, 2006, we had outstanding $225 million (principal amount) of 7.5% subordinated notes due 2013, $150 million

DENBURY RESOURCES INC.

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

(principal amount) of 7.5% subordinated notes due 2015, approximately $100 million of bank debt, and $6.5 million of capital leases. As of April 30, 2006, the bank debt had been repaid with the proceeds from the equity offering.

Sources and Uses of Capital Resources

During the first quarter of 2006, we incurred $118.6 million on oil and natural gas exploration and development expenditures, $11.0 million on 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 on drilling, $6.1 million on geological, geophysical and acreage expenditures and $55.9 million incurred on 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 the balance funded 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.

During the first quarter of 2005, we incurred $57.2 million on oil and natural gas exploration and development expenditures, $28.0 million on CO₂ exploration and development expenditures (including $19.0 million on our CO₂ pipeline being constructed to East Mississippi), and approximately $30.8 million on property acquisitions, for total capital expenditures of approximately $116.0 million. Our exploration and development expenditures included approximately $24.1 million incurred on drilling, $6.4 million on geological, geophysical and acreage expenditures and $26.7 million incurred on facilities and recompletion costs. We funded these expenditures with $66.6 million of cash flow from operations, an $11.2 million increase in our accrued capital expenditures, with the balance funded with cash remaining from our 2004 offshore property sale.

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. Further, one of our subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed the bank debt of Genesis (which as of March 31, 2006, consisted of $2.6 million of debt and $10.7 million in letters of credit) and we have delivery obligations to deliver CO₂ to our industrial customers. 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 2005 amounts reflected in our Form 10-K filed in March 2006. 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 2005 Form 10-K for further information regarding our commitments and obligations.

Results of Operations

CO₂Operations

As described in the “Overview” section above, our CO₂ operations are 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 2005 Form 10-K for further information regarding these matters.

DENBURY RESOURCES INC.

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

We plan to drill three additional CO₂ source wells during 2006. The first well drilled in early 2006 is currently testing, and although preliminary indications are that it added only minor incremental reserves, it should, upon completion, further increase our maximum potential CO₂ production rate by 10 MMcf/d to 20 MMcf/d, to a total level between 450 MMcf/d to 500 MMcf/d. Drilling is expected to continue for the foreseeable future in an attempt to further increase our production capacity and potentially increase our proven CO₂reserves. During the first quarter of 2006, our CO₂ production averaged 288 MMcf/d. We used 77% of this, or 220 MMcf/d, in our tertiary operations, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payment.

Oil production from our tertiary operations increased to an average of 9,758 BOE/d in the first quarter of 2006, a 13% increase over the first quarter 2005 tertiary production level of 8,644 BOE/d and about the same as fourth quarter 2005 tertiary production levels. The tertiary oil production response has been slower than anticipated, particularly at McComb Field, primarily because we have not been able to inject CO₂ as fast as we originally planned. In comparing McComb Field to Little Creek Field, our most mature tertiary project, McComb is recovering oil at a similar rate as Little Creek when you compare oil production versus CO₂ injection volumes. Thus, the CO₂ appears to be working as effectively in McComb as it did in Little Creek, but since our CO₂ injection rate is lower than projected, our oil production there is lagging as well. Although we are still testing our theory, we believe that by raising the CO₂ injection pressure we may remedy this situation in the future, although it will take some time to meaningfully impact on our production rates. As such, we lowered our 2006 tertiary oil production target in late March from 13,000 BOE/d, to a range of 11,750 BOE/d and 12,750 BOE/d.


	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First
	Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2005		2005		2005		2005		2006

Brookhaven		—		—		—		125		547
Little Creek & Lazy Creek		3,709		3,847		3,357		3,210		3,006
Mallalieu (East and West)		4,235		4,582		4,565		5,562		5,219
McComb & Olive		700		988		928		1,011		932
Smithdale		—		—		—		31		54

Total tertiary oil production		8,644		9,417		8,850		9,939		9,758

We spent approximately $0.20 per Mcf to produce our CO₂during the first quarter of 2006, slightly higher than our 2005 average of $0.16 per Mcf, primarily due to increased labor, utilities and equipment rental expense during the first part of 2006, coupled with higher royalty expenses because most of our royalties correlate with oil prices. Our estimated total cost per thousand cubic feet of CO₂during the first quarter of 2006 was approximately $0.28, after inclusion of depreciation and amortization expense, also up slightly from the 2005 average of $0.25 per Mcf for these same reasons.

For the first quarter of 2006, our operating costs for our tertiary properties averaged $15.02 per BOE, higher than the prior year average of $12.00 per BOE, slightly higher than our fourth quarter of 2005 average of $14.57 per BOE. The higher costs were a result of the higher CO₂ costs (see prior paragraph), higher fuel and energy costs (which represent almost 38% of the total operating costs excluding the cost of CO₂), higher rental payments on leased equipment, and general cost inflation in the industry.

Operating Results

As summarized in the “Overview” section above and discussed in more detail below, higher commodity prices and production more than offset higher operating expenses, resulting in near-record quarterly earnings and cash flow from operations. Included in the first quarter of 2006 net income is the effect of approximately $2.1 million ($1.9 million after tax) of non-cash charges related to the adoption of SFAS No. 123(R) as of January 1, 2006, relating to the certain stock-based compensation that was previously only reflected as a footnote disclosure and not recorded in the financial statements (See Note 4 to the Unaudited Condensed Consolidated Financial Statements).

DENBURY RESOURCES INC.

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


	Three Months Ended
	March 31,
Amounts in thousands, except per share amounts	2006			2005
Net income	$	43,778		$	30,067
Net income per common share — basic		0.39			0.27
Net income per common share — diluted		0.37			0.26

Adjusted cash flow from operations (see below)	$	107,849		$	69,411
Net change in assets and liabilities relating to operations		(5,337	)		(2,782	)

Cash flow from operations (1)	$	102,512		$	66,629


(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. 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 and an increase in our accrued production receivables during the first quarter of 2005 caused primarily by rising commodity prices. These increases were partially offset by changes in other current assets and liabilities.

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 2006 and 2005 are included in the following table.


	Three Months Ended
	March 31,
	2006			2005
Average daily production volume
Bbls/d		22,211			20,263
Mcf/d		79,452			56,766
BOE/d (1)		35,454			29,724

Operating revenues (thousands)
Oil sales	$	113,441		$	79,182
Natural gas sales		62,102			31,834

Total oil and natural gas sales	$	175,543		$	111,016


Oil and gas derivative contracts⁽²⁾(thousands)
Cash expense on settlement of derivative contracts	$	(768	)	$	(1,099	)
Non-cash derivative expense		(10,862	)		(6,722	)

Total expense from oil and gas derivative contracts	$	(11,630	)	$	(7,821	)


Operating expenses (thousands)
Lease operating expenses	$	36,172		$	22,962
Production taxes and marketing expenses		8,087			6,126

Total production expenses	$	44,259		$	29,088


CO₂ sales and transportation fees (3)	$	1,988		$	1,730
CO₂ operating expenses		(645	)		(346	)

CO₂ operating margin	$	1,343		$	1,384


Unit prices — including impact of derivative settlements
Oil price per Bbl	$	56.36		$	43.42
Gas price per Mcf		8.68			6.02

Unit prices — excluding impact of derivative settlements
Oil price per Bbl	$	56.75		$	43.42
Gas price per Mcf		8.68			6.23

Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues	$	55.01		$	41.50

Oil and gas lease operating expenses	$	11.34		$	8.58
Oil and gas production taxes and marketing expense		2.53			2.29

Total oil and gas production expenses	$	13.87		$	10.87


(1)		Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of natural gas (“BOE”).

(2)		See also “Market Risk Management” below for information concerning the Company’s derivative transactions.

(3)		Includes deferred revenue of $940,000 and $622,000 for 2006 and 2005, respectively, associated with volumetric production payments and $1.0 million and $717,000, respectively, of transportation income, both from Genesis.

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 2005 and the first quarter of 2006 is listed in the following table.


	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First
	Quarter		Quarter		Quarter		Quarter		Quarter
Operating Area	2005		2005		2005		2005		2006

Mississippi — non-CO2 floods		13,057		12,788		10,998		11,475		12,455

Mississippi — CO2 floods		8,644		9,417		8,850		9,939		9,758

Onshore Louisiana		6,710		5,791		5,169		6,992		8,349

Barnett Shale		1,313		2,052		2,150		3,048		3,953

Alabama		—		37		126		141		917

Other⁽¹⁾		—		384		52		54		22

Total Company		29,724		30,469		27,345		31,649		35,454


(1)		Primarily represents production from an offshore property retained from sale in July 2004.

As outlined in the above table, production in the first quarter of 2006 increased 19% over first quarter of 2005 levels and 12% over the prior fourth quarter levels. Of this increase, the January 2006 acquisition contributed two months of production, or approximately 1,476 BOE/d of the increase in quarterly average production (686 BOE/d to the Mississippi – non-CO₂ floods and 790 BOE/d to Alabama in the above table). In addition, our onshore Louisiana production increased 1,357 BOE/d over the prior quarter levels, with the most significant production increases at Thornwell and South Chauvin Fields as a result of recent drilling activity in that area. Our production in the Barnett Shale area increased 905 BOE/d, also as a result of increased drilling activity, with 40 to 50 wells planned for that area in 2006. Production in the Mississippi – non-CO₂ floods area was up only slightly from fourth quarter levels (before giving effect to the January 2006 acquisition related increase noted above), primarily related to additional natural gas production at Heidelberg Field related to continued development of the Selma Chalk. See “CO₂ Operations” above for a discussion of the tertiary related production.

Oil and Natural Gas Revenues:Oil and natural gas revenues for the first quarter of 2006 increased $64.5 million, or 58%, from revenues in the comparable quarter of 2005, as a result of higher commodity prices and increased production. Cash payments on our derivative contracts were $768,000 in the first quarter of 2006, down 30% from the $1.1 million paid during the first quarter of 2005, as less than 10% of our total production was covered by a derivative contract in either period. See “Market Risk Management” for additional information regarding our derivative activities.

The 19% increase in production in the first quarter of 2006 increased oil and natural gas revenues, when comparing the two first quarters, by $21.4 million, or 19% while the increase in overall commodity prices increased revenue by $43.1 million, or 39%, in the first quarter of 2006 as compared to the prior year first quarter. Our realized natural gas prices (excluding hedges) for the first quarter of 2006 averaged $8.68 per Mcf, a 39% increase from the average of $6.23 per Mcf realized during the first quarter of 2005, and our realized oil prices (excluding hedges) for the first quarter of 2006 averaged $56.75 per Bbl, a 31% increase from the $43.42 per Bbl average realized in the first quarter of 2005. On a combined BOE basis, commodity prices were 33% higher in the first quarter of 2006 as compared to prices in the first quarter of 2005.

The differentials between our net realized oil prices (excluding commodity derivative contracts) and NYMEX prices were only slightly higher in the first quarter of 2006 than in the first quarter of 2005, both of which were also similar to the fourth quarter of 2005 differentials. Our average oil differential for the first quarter of 2006 was approximately $6.71 per Bbl as compared to $6.54 per Bbl during the first quarter of 2005 and an average of $6.17 per Bbl during the fourth quarter of 2005. The higher overall differential in the first quarter of 2006 was primarily related to lower light sweet

DENBURY RESOURCES INC.

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

prices relative to NYMEX during the period as the heavier sour crude differentials improved slightly. These trends are difficult to accurately forecast.

Our natural gas differentials relative to NYMEX improved in the first quarter compared to the first and fourth quarters of 2005. The variance improved this quarter, at least in part, due to decreasing natural gas prices during the first quarter of 2006. 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. Our average natural gas differential for the first quarter of 2006 was a positive variance of approximately $0.78 per Mcf, as compared to a negative variance of $0.23 per Mcf during the first quarter of 2005 and a negative variance of $1.03 per Mcf during the fourth quarter of 2005.

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) general cost inflation in our industry, (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. The adoption of SFAS No. 123(R) effective January 1, 2006 (see “Overview – Operating results”) also added approximately $366,000 of non-cash charges to first quarter 2006 lease operating expense representing the stock compensation expense pertaining to operating personnel.

During the first quarter of 2006, operating costs averaged $11.34 per BOE, up from $8.58 per BOE in the first quarter of 2005, and up slightly from the $11.28 per BOE in the fourth quarter of 2005. Operating expenses on our tertiary operations increased from $7.9 million in the first quarter of 2005 to $13.2 million during the first quarter of 2006, as a result of the increased tertiary activity level. Tertiary operating expenses were particularly impacted by the higher power and energy costs, higher costs for CO₂ and payments on leased facilities and equipment (see “CO₂ Operations” above). We expect this increase in tertiary operating costs to continue and to further increase our cost per BOE as tertiary production becomes a more significant portion of our total production and operations. Lease operating expenses related to the properties acquired in the January acquisition were $2.3 million during the first quarter of 2006.

Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes and therefore were higher in the first quarter of 2006 than in the comparable quarter of 2005.

General and Administrative Expenses

General and administrative (“G&A”) expenses increased 52% between the respective first quarters as set forth below:


	Three Months Ended
	March 31,
	2006			2005
Net G&A expense (thousands)
Gross G&A expenses	$	21,340		$	14,378
State franchise taxes		412			309
Operator labor and overhead recovery charges		(9,909	)		(6,986	)
Capitalized exploration costs		(1,976	)		(1,206	)

Net G&A expense	$	9,867		$	6,495

Average G&A cost per BOE	$	3.09		$	2.43
Employees as of March 31		507			400

Gross G&A expenses increased $7.0 million, or 48%, between the first quarters of 2006 and 2005. As discussed in “Overview – Operating results” above, the adoption of SFAS No. 123(R) in January 2006 increased net G&A expense by approximately $1.7 million (gross G&A expense by $2.4 million), representing the non-cash charge for stock compensation (mainly stock options and stock appreciation rights) pertaining to personnel charged to G&A. In addition, both comparative periods include approximately $1.0 million of non-cash compensation expense associated with the amortization of deferred compensation resulting from the issuance of restricted stock to officers and directors during 2004 which was already being expensed prior to the adoption of SFAS No. 123(R). The balance of the G&A increase in 2006

DENBURY RESOURCES INC.

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

primarily relates to higher compensation costs associated with the additional personnel hired during 2005 and the first quarter of 2006, although these incremental compensation costs on a BOE basis were minimal because of the higher production in the 2006 period. During 2005, we added 80 employees and we further increased our employee count by 47 during 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 2006. 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 increases in field operating personnel, our incremental drilling and development activity during the first quarter of 2006 and the allocation of SFAS No. 123(R) stock based compensation to operations commencing January 1, 2006, the amount we recovered as operator overhead charges increased by 42% ($2.9 million) between the respective first quarters of 2006 and 2005. Capitalized exploration costs also increased between the comparable periods in 2006 and 2005, primarily as a result of increased compensation costs, most of which relate to stock based compensation that was not included in our financial statements prior to the adoption of SFAS No. 123(R).

The net effect was a 52% increase in net G&A expense between the respective first quarters. On a per BOE basis, G&A costs increased 27% in the first quarter of 2006 as compared to those costs in the first quarter of 2005, a lower percentage increase than the increase in gross costs as a result of the higher production levels and primarily related to the adoption of SFAS No. 123(R).

Interest and Financing Expenses


	Three Months Ended
	March 31,
Amounts in thousands, except per BOE amounts	2006			2005
Cash interest expense	$	8,268		$	4,533
Non-cash interest expense		260			205
Less: Capitalized interest		(274	)		(262	)

Interest expense	$	8,254		$	4,476

Interest and other income	$	1,375		$	616
Average net cash interest expense per BOE⁽¹⁾	$	2.07		$	1.37
Average interest rate⁽²⁾		7.4	%		7.5	%
Average debt outstanding	$	446,953		$	240,632


(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.

Interest expense increased $3.8 million, or 84%, comparing the first quarters of 2005 and 2006 as average debt levels almost doubled. Debt levels were unusually low in the first quarter of 2005 following the sale of our offshore properties in mid-2004. Conversely, debt levels were high in the first quarter of 2006 following the $248 million acquisition which closed at the end of January, funded by $150 million of subordinated debt issued in December 2005 and $100 million of bank debt borrowed at closing. The bank debt was repaid in April 2006 with the proceeds from the recent equity offering (see “Overview – April 2006 Equity Offering”).

DENBURY RESOURCES INC.

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

Depletion, Depreciation and Amortization


	Three Months Ended
	March 31,
Amounts in thousands, except per BOE amounts	2006		2005
Depletion and depreciation of oil and natural gas properties	$	29,317	$	19,410
Depletion and depreciation of CO₂ assets		1,930		1,206
Asset retirement obligations		571		321
Depreciation of other fixed assets		925		591

Total DD&A	$	32,743	$	21,528

DD&A per BOE:
Oil and natural gas properties	$	9.37	$	7.38
CO₂ assets and other fixed assets		0.89		0.67

Total DD&A cost per BOE	$	10.26	$	8.05

Our depletion, depreciation and amortization (“DD&A”) rate on a per BOE basis increased 5% over the fourth quarter of 2005 DD&A rate of $9.80 per BOE, and increased 27% between the respective first quarters, primarily due to rising costs. We allocated approximately $123 million of our $248 million January 2006 acquisition to unevaluated properties to reflect the significant potential probable and possible reserves that we considered 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 2006, which historically have had a lower finding and development cost than our overall company average. Although we have initiated CO₂injections at three East Mississippi fields in the second quarter of 2006, it is unlikely that we will book any significant tertiary reserves in these fields until late in the year and the magnitude of these potential reserves will largely depend on the timing of the production response at two of these fields, Soso and Martinville. 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 2006 as compared to the comparative quarter in 2005 as a result of the additional cost incurred drilling CO₂wells during each year and higher associated future development costs, partially offset by an increase in CO₂reserves from 2.7 Tcf as of December 31, 2004, to 4.6 Tcf as of December 31, 2005 (100% working interest basis before amounts attributable to Genesis volumetric production payments).

Income Taxes


	Three Months Ended
	March 31,
Amounts in thousands, except per BOE amounts and tax rates	2006			2005
Current income tax expense	$	9,786		$	5,282
Deferred income tax provision		18,184			8,546

Total income tax provision	$	27,970		$	13,828

Average income tax expense per BOE	$	8.77		$	5.17
Effective tax rate		39.0	%		31.5	%

DENBURY RESOURCES INC.

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

Our income tax provision for the first quarter of 2006 and 2005 was based on an estimated statutory tax rate of 39%. For the first quarter of 2005, our net effective tax rate was 31.5%, lower than the statutory rates primarily due to the recognition of enhanced oil recovery credits (“EOR”) which lowered our overall tax expense. For the first quarter of 2006, because of the high oil prices during 2005, we will not be earning any EOR credits during 2006, thus increasing our net effective tax rate to near 39%. Under the recently adopted accounting rules under SFAS No. 123(R), a tax benefit, if any, for compensation expenses arising from the issuance of incentive stock options (the majority of our options issued prior to 2006) is not recognizable during the vesting period, the period during which they are expensed for book purposes, which also caused a slight increase in our effective tax rate in the first quarter of 2006.

In both periods, the current income tax expense represents our anticipated alternative minimum cash taxes that we cannot offset with regular tax net operating loss carryforwards or EOR credits. As of December 31, 2005, we had an estimated $42.1 million of EOR credits carryforwards that we can utilize to reduce our current income taxes during 2006, even though we are not earning any additional EOR 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	2006			2005
Oil and natural gas revenues	$	55.01		$	41.50
Loss on settlements of derivative contracts		(0.24	)		(0.41	)
Lease operating expenses		(11.34	)		(8.58	)
Production taxes and marketing expenses		(2.53	)		(2.29	)

Production netback		40.90			30.22
CO₂ operating margin		0.42			0.52
General and administrative expenses		(3.09	)		(2.43	)
Net cash interest expense		(2.07	)		(1.37	)
Current income taxes and other		(2.36	)		(0.99	)
Changes in assets and liabilities relating to operations		(1.67	)		(1.04	)

Cash flow from operations		32.13			24.91
DD&A		(10.26	)		(8.05	)
Deferred income taxes		(5.70	)		(3.19	)
Non-cash derivative adjustments		(3.40	)		(2.51	)
Changes in assets and liabilities and other non-cash items		0.95			0.08

Net income	$	13.72		$	11.24

Market Risk Management

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 $100 million of bank debt outstanding as of March 31, 2006 and none at December 31, 2005. 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.

DENBURY RESOURCES INC.

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


	Expected Maturity Dates				Carrying Fair
Amounts in thousands	2006 - 2010		Value		Value
Variable rate debt:
Bank debt	$	100,000	$	100,000	$	100,000
(The weighted average interest rate at March 31, 2006 was 6.08%)
Fixed rate debt:
7.5% subordinated debt due 2013, net of discount		—		223,640		233,438
(The interest rate on the subordinated debt is a fixed rate of 7.5%)
7.5% subordinated debt, due 2015		—		150,000		156,000
(The interest rate on the subordinated debt is a fixed rate of 7.5%)

From time to time, we enter into various derivative contracts to economically hedge 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. For 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. (Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the sections entitled “Market Risk Management” contained in our 2005 Form 10-K for further information regarding our hedging activities). 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, 2006, the only derivative contracts we have in place relate to the $248 million acquisition that closed on January 31, 2006, on which we entered into contracts to cover 100% of the estimated proved producing production for three years at the time we signed the purchase and sale agreement in November 2005. While these derivative contracts related to the acquisition represent less than 6% of our estimated 2006 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 2,200 Bbls/d for 2006 at a price of $59.65 per Bbl; 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, 2006, our derivative contracts were recorded at their fair value, which was a net liability of approximately $20.2 million, an increase of approximately $10.8 million from the $9.4 million fair value liability recorded as of December 31, 2005. 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 prices between December 31, 2005 and March 31, 2006.

Based on NYMEX crude oil futures prices at March 31, 2006, oil prices were considerably higher than the swap prices of our outstanding derivative contracts so we would not expect to receive any funds even if oil prices were to drop 10%. Based on NYMEX futures prices at March 31, 2006, we would expect to make future cash payments of $21.5 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 $7.3 million, and if futures prices were to increase by 10% we would expect to pay $35.8 million.

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, 2005.

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

DENBURY RESOURCES INC.

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

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.

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.

In January 2005, we began processing our transactions on a newly implemented accounting software system. We are continuing to fine-tune and implement additional aspects of the new system. While we believe that the new system is working properly in all material respects and has improved our overall internal controls, we are continuing to evaluate the impact and effect of a new accounting system on our internal controls and procedures and it is possible that we may find weaknesses in the future.

During 2005 and 2006, information was reported on our whistleblower hotline regarding misconduct by oilfield vendors and certain employees, including alleged improper billings and payments by certain vendors to, or on behalf of employees, misuse of Company property and operational information, and the failure by certain employees to properly report certain transactions with the Company. During 2005 and continuing into 2006, at the direction of the Audit Committee of our Board of Directors, and in conjunction with outside counsel retained by the Audit Committee, investigations have been undertaken regarding these matters. These investigations are ongoing. As a result of our investigations to date, we have dismissed four employees, taken disciplinary action against another employee, and terminated all future business with certain vendors. The estimated amount of improper vendor billings and payments discovered to date is inconsequential to our previously issued financial statements and to the financial statements contained in this report on Form 10-Q. We further believe that the ultimate resolution of these matters will not materially adversely affect our financial condition, results of operations or business. We believe that our whistleblower hotline was effective in alerting us to improper vendor and employee conduct and allowing us to remedy the matter.

Controls and policies in place to prevent these occurrences were overridden by employee misconduct in the vendor approval and payment process and in adherence to the Company’s Code of Business Conduct and Ethics. As a result of our investigation, we have, and are continuing, to implement certain improvements to strengthen our management practices and policies and internal controls (see also Item 9A. “Controls and Procedures” – “Disclosure Controls and Procedures” contained in our 2005 Form 10-K for further information).

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, 2005. 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, 2005.

DENBURY RESOURCES INC.

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

ISSUER PURCHASES OF EQUITY SECURITIES


					(c) Total Number of		(d) Maximum Number
	(a) Total				Shares Purchased		of Shares that May
	Number of		(b) Average		as Part of Publicly		Yet Be Purchased
	Shares		Price Paid		Announced Plans or		Under the Plan Or
Period	Purchased		per Share		Programs		Programs
January 1 through 31, 2006		293		24.38		—		—
February 1 through 28, 2006		—		—		—		—
March 1 through 31, 2006		—		—		—		—
Total		293		24.38		—		—

These shares were purchased from employees of Denbury who delivered shares to the Company to satisfy their minimum tax withholding requirements related to the vesting of restricted shares.

DENBURY RESOURCES INC.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

Item 6. Exhibits


Exhibits:
10*		Amendment for increased borrowing base from $200 million to $300 million related to the Fifth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, Denbury Resources Inc, as Parent Guarantor, Bank One, N.A. as Administrative Agent, and certain other financial institutions effective as of March 29, 2006.

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.

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 5, 2006

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Denbury (DNRWW) 10-Q2006 Q1 Quarterly report

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