Edgar Filing: DENBURY RESOURCES INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 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. Yes þ No o

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 filer þ Accelerated filer o Non-accelerated filer o

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

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


		Class		Outstanding at July 31, 2006
		Common Stock, $.001 par value		119,268,944

INDEX


		Page
Part I. Financial Information

Item 1. Financial Statements

Unaudited Condensed Consolidated Balance Sheets at June 30, 2006 and December 31, 2005		3

Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005		4

Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2006 and 2005		5

Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 30, 2006 and 2005		6

Notes to Unaudited Condensed Consolidated Financial Statements		7- 20

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21-34

Item 3. Quantitative and Qualitative Disclosures about Market Risk		35

Item 4. Controls and Procedures		35

Part II. Other Information

Item 1. Legal Proceedings		35

Item 1A. Risk Factors		35

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		36

Item 3. Defaults Upon Senior Securities		36

Item 4. Submission of Matters to a Vote of Security Holders		36

Item 5. Other Information		36

Item 6. Exhibits		37

Signatures		38
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares)


	June 30,			December 31,
	2006			2005
Assets
Current assets
Cash and cash equivalents	$	30,812		$	165,089
Accrued production receivable		70,795			65,611
Related party receivable — Genesis		288			1,312
Trade and other receivables		32,827			25,887
Deferred tax asset		16,597			41,284

Total current assets		151,319			299,183


Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		2,052,241			1,669,579
Unevaluated		236,903			46,597
CO₂ properties and equipment		238,229			210,046
Other		38,212			34,647
Less accumulated depletion and depreciation		(872,517	)		(804,899	)

Net property and equipment		1,693,068			1,155,970


Investment in Genesis		10,932			10,829
Deposits on property acquisitions		126			26,425
Other assets		14,023			12,662

Total assets	$	1,869,468		$	1,505,069


Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	97,199		$	104,840
Oil and gas production payable		50,128			41,821
Derivative liabilities		13,113			2,759
Deferred revenue — Genesis		4,070			4,070
Short-term capital lease obligations — Genesis		602			574

Total current liabilities		165,112			154,064


Long-term liabilities
Capital lease obligations — Genesis		5,561			5,870
Long-term debt		443,688			373,591
Asset retirement obligations		34,566			25,297
Derivative liabilities		16,449			6,624
Deferred revenue — Genesis		31,018			33,023
Deferred tax liability		195,930			170,758
Other		2,881			2,180

Total long-term liabilities		730,093			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; 119,565,186 and 115,038,531 shares issued at June 30, 2006 and December 31, 2005, respectively		120			115
Paid-in capital in excess of par		596,899			443,283
Retained earnings		383,615			295,575
Treasury stock, at cost, 344,985 and 340,337 shares at June 30, 2006 and December 31, 2005, respectively		(6,371	)		(5,311	)

Total stockholders’ equity		974,263			733,662

Total liabilities and stockholders’ equity	$	1,869,468		$	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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006		2005
Revenues and other income
Oil, natural gas and related product sales
Unrelated parties	$	189,369		$	124,277		$	363,463	$	234,810
Related party — Genesis		35			1,495			1,484		1,978
CO₂ sales and transportation fees		2,374			1,517			4,362		3,247
Interest income and other		1,469			694			2,844		1,310

Total revenues		193,247			127,983			372,153		241,345


Expenses
Lease operating expenses		41,751			26,757			77,923		49,719
Production taxes and marketing expenses		8,441			5,528			15,386		10,718
Transportation expense — Genesis		995			1,054			2,137		1,990
CO₂ operating expenses		785			445			1,430		791
General and administrative		14,574			5,992			24,441		12,487
Interest, net of amounts capitalized of $2,735, $373, $3,009, and $635, respectively		5,751			4,335			14,005		8,811
Depletion, depreciation, and amortization		36,152			24,405			68,895		45,933
Commodity derivative expense (income)		11,529			(1,025	)		23,159		6,796

Total expenses		119,978			67,491			227,376		137,245


Equity in net income of Genesis		319			44			559		331


Income before income taxes		73,588			60,536			145,336		104,431

Income tax provision (benefit)
Current income taxes		(2,349	)		4,354			7,437		9,636
Deferred income taxes		31,675			15,510			49,859		24,056

Net income	$	44,262		$	40,672		$	88,040	$	70,739


Net income per common share — basic	$	0.38		$	0.37		$	0.77	$	0.64

Net income per common share — diluted	$	0.36		$	0.34		$	0.72	$	0.60

Weighted average common shares outstanding
Basic		116,471			111,306			114,820		111,114
Diluted		122,988			117,944			121,912		118,071

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Cash flow from operating activities:
Net income	$	44,262		$	40,672		$	88,040		$	70,739
Adjustments needed to reconcile to net cash flow provided by operations:
Depletion, depreciation and amortization		36,152			24,405			68,895			45,933
Non-cash hedging adjustments		9,317			(2,801	)		20,179			3,921
Deferred income taxes		31,675			15,510			49,859			24,056
Deferred revenue — Genesis		(1,065	)		(670	)		(2,005	)		(1,292	)
Stock based compensation		8,285			1,031			11,257			2,059
Current income tax benefit from stock options		—			3,354			—			5,434
Amortization of debt issue costs and other		167			450			417			512
Changes in assets and liabilities:
Accrued production receivable		(4,317	)		(1,475	)		(4,160	)		(7,394	)
Trade and other receivables		(10,198	)		(5,422	)		(5,940	)		(8,510	)
Other assets		7,500			—			(2,632	)		130
Accounts payable and accrued liabilities		(19,027	)		8,574			(23,768	)		15,818
Oil and gas production payable		3,440			4,981			8,306			4,298
Other liabilities		226			(224	)		481			(690	)


Net cash provided by operations		106,417			88,385			208,929			155,014


Cash flow used for investing activities:
Oil and natural gas expenditures		(131,502	)		(81,685	)		(250,101	)		(138,880	)
Acquisitions of oil and gas properties		(61,925	)		(37,763	)		(314,335	)		(68,544	)
Change in accrual for capital expenditures		4,584			(2,249	)		14,612			8,990
Acquisitions of CO₂ assets and capital expenditures		(17,143	)		(7,155	)		(28,167	)		(35,118	)
Net purchases of other assets		(1,520	)		(1,169	)		(3,460	)		(3,099	)
Proceeds from oil and gas property sales		2,038			(5	)		2,038			(23	)
Deposits on acquisitions		—			—			26,299			4,507
Sales of short-term investments		—			12,558			—			55,133
Increase in restricted cash		(27	)		(62	)		(65	)		(110	)


Net cash used for investing activities		(205,495	)		(117,530	)		(553,179	)		(177,144	)


Cash flow from financing activities:
Bank repayments		(130,000	)		(5,800	)		(130,000	)		(19,800	)
Bank borrowings		100,000			15,800			200,000			29,800
Payments on capital lease obligations — Genesis		(142	)		(129	)		(280	)		(254	)
Issuance of common stock		127,846			3,464			132,311			7,825
Current income tax benefit from stock options		4,317			—			10,152			—
Purchase of treasury stock		(2,115	)		(1,616	)		(2,122	)		(3,164	)
Costs of debt financing		—			—			(88	)		—


Net cash provided by financing activities		99,906			11,719			209,973			14,407


Net increase (decrease) in cash and cash equivalents		828			(17,426	)		(134,277	)		(7,723	)

Cash and cash equivalents at beginning of period		29,984			42,742			165,089			33,039


Cash and cash equivalents at end of period	$	30,812		$	25,316		$	30,812		$	25,316


Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	14,772		$	8,647		$	15,897		$	8,906
Cash paid during the period for income taxes		4,200			7,500			4,206			7,500
Interest capitalized		2,735			373			3,009			635

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS

(In thousands)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Net income	$	44,262	$	40,672	$	88,040	$	70,739
Other comprehensive income, net of income tax:
Reclassification adjustments related to settlements of derivative contracts, net of tax of $669 and $1,359, respectively		—		1,092		—		2,217
Unrealized gain on securities available for sale		—		22		—		24

Comprehensive income	$	44,262	$	41,786	$	88,040	$	72,980

(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 June 30, 2006 and the consolidated results of its operations and cash flows for the three and six month periods ended June 30, 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, stock appreciation rights (“SARs”) and any other convertible securities outstanding. For the three and six month periods ended June 30, 2006 and 2005, there were no adjustments to net income for purposes of calculating diluted net income per common share. In April 2006 we issued 3,492,595 shares of common stock in a public offering – See Note 3, Shareholders’ Equity. 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 and six month periods ended June 30, 2006 and 2005.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Shares in Thousands)	2006		2005		2006		2005
Weighted average common shares — basic		116,471		111,306		114,820		111,114

Potentially dilutive securities:
Stock options and SARs		5,498		5,746		6,094		6,136
Restricted stock		1,019		892		998		821

Weighted average common shares — diluted		122,988		117,944		121,912		118,071

The weighted average common shares – basic amount excludes 1,687,539 shares at June 30, 2006 and 2,320,000 shares at June 30, 2005, of non-vested restricted stock that is subject to future vesting over time. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2006 and 2005, stock options to purchase approximately 60,000 and 125,000 shares of common stock, and for the six months ended June 30, 2006 and 2005, stock options to purchase approximately 66,000 and 179,000 shares of common stock, respectively, 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 these periods and would be anti-dilutive to the calculations.

Stock-based Compensation

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“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 Accounting Principles Board Opinion 25 (“APB 25”), “Accounting for Stock Issued to Employees,” 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 6 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 have begun our initial tertiary development work at Tinsley Field, consisting primarily of planning, land and engineering work, with more extensive development and facility construction planned for 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 adjusted purchase price for these properties was approximately $250 million, after adjusting for interim net cash flow between the effective date and closing date of the acquisition, and minor purchase price adjustments. The adjusted purchase price of $250 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, approximately $126 million was assigned to proved properties and approximately $124 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 with proceeds from a $125 million equity offering).

During May 2006, we purchased the Delhi Holt-Bryant Unit (“Delhi”) in northern Louisiana for $50 million, plus a 25% reversionary interest to the seller after we have achieved $200 million in net operating revenue, as defined. Delhi is also a future potential CO₂ tertiary oil flood candidate, one that will require construction of a CO₂ pipeline before flooding can commence, which will likely be an extension of the currently planned CO₂ pipeline from Jackson Dome to Tinsley Field. We hope to have this CO₂ line installed within the next two to three years, with initial oil production from tertiary operations currently anticipated during 2010. Currently, there are neither significant oil production nor proved oil reserves at Delhi. The purchase price of approximately $50 million was

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 the analysis, approximately $1 million was assigned to evaluated properties and approximately $49 million was assigned to unevaluated properties. The unevaluated costs are currently excluded from the amortization base and will be transferred to the amortization base over the next three to five years as we develop and test the tertiary recovery projects planned in this field. The acquisition was funded with our existing bank credit facility.

The operating results of the acquired properties were included in our financial statements beginning in February 2006, except for Delhi, which was included beginning June 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 three or six months ended June 30, 2006 and 2005.

3. SHAREHOLDERS’ EQUITY

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 then 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 $250 million acquisition of three properties in January 2006.

4. 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 six months ended June 30, 2006.


	Six Months Ended
	June 30, 2006
	(in thousands)
Beginning asset retirement obligation, as of 12/31/2005	$	27,088
Liabilities incurred and assumed during period		9,218
Revisions in estimated cash flows		378
Liabilities settled during period		(352	)
Accretion expense		1,186

Ending asset retirement obligation as of 6/30/2006	$	37,518

At June 30, 2006, $3.0 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 and assumed during the period are primarily for oil properties acquired during 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 both June 30, 2006 and December 31, 2005 and are included in “Other assets” in our Condensed Consolidated Balance Sheets.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS


	June 30,			December 31,
(In Thousands)	2006			2005
7.5% Senior Subordinated Notes due 2015	$	150,000		$	150,000
7.5% Senior Subordinated Notes due 2013		225,000			225,000
Discount on Senior Subordinated Notes due 2013		(1,312	)		(1,409	)
Senior bank loan		70,000			—
Capital lease obligations — Genesis		6,163			6,444

Total		449,851			380,035
Less current obligations		602			574

Long-term debt and capital lease obligations	$	449,249		$	379,461

6. 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 June 30, 2006, a total of 1,160,471 shares were available for future issuance of awards, of which only 383,771 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 for employees with SARs settled in stock, 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 defined in the 2004 Plan as the closing price on the NYSE on the date of grant. The plan is administered by the Compensation Committee of Denbury’s Board of Directors.

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.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Mr. Worthey, Senior Vice President of Operations, left Denbury effective June 5, 2006. Mr. Worthey had served as an officer of the Company since September 1, 1992. The Board of Directors modified certain of his outstanding long-term equity incentives awarded to him during 2003 and 2004. As a result of the modification, Mr. Worthey retained stock options covering 63,090 shares of Denbury common stock, which pursuant to their original terms vest in either January 2007 or January 2008, and received accelerated vesting of 136,500 shares of restricted stock which originally were set to vest between mid-August 2006 and mid-August 2008. The options have an average weighted exercise price of $6.26 per share and were granted in early 2003 and early 2004; the restricted stock was awarded in August 2004. The compensation cost resulting from the modifications was approximately $5.3 million and was included in “General and administrative expenses” in the Condensed Consolidated Statement of Operations for the Three Months Ended June 30, 2006. No significant cash compensation was paid to Mr. Worthey upon separation. As part of Mr. Worthey’s separation, he also entered into non-competition and consulting agreements covering a period of twenty-seven months.

The total compensation expense that has been charged against income for stock-based compensation was $8.3 million and $11.3 million (including the $5.3 million resulting from the modifications discussed above) for the three and six months ended June 30, 2006, respectively. Part of this expense, $0.3 million and $0.7 million for the three and six months ended June 30, 2006, respectively, was included in “Lease operating expenses” for the stock compensation expense associated with our field employees, and the remaining $8.0 million and $10.6 million for the three and six months ended June 30, 2006, respectively, was recognized in “General and administrative expenses” in the Condensed Consolidated Statements of Operations. The total income tax benefit recognized in the Condensed Consolidated Statements of Operations for share-based compensation arrangements was $2.0 million and $2.1 million for the three and six months ended June 30, 2006, respectively. Share-based compensation capitalized as part of “Oil and Natural Gas Properties” was $0.4 million and $0.9 million for the three and six months ended June 30, 2006, respectively.

Prior to 2006, we accounted for 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 was reflected in net income as long as the stock options had 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 SFAS No. 123, as amended by SFAS No. 148, in accounting for our stock-based compensation.


	Three Months		Six Months
	Ended June 30,		Ended June 30,
(In Thousands, except per share amounts)	2005		2005
Net income, as reported	$	40,672	$	70,739
Add: stock-based compensation included in reported net income, net of related tax effects		693		1,394
Less: stock-based compensation expense applying fair value based method, net of related tax effects		1,874		3,490

Pro-forma net income	$	39,491	$	68,643


Net income per common share
As reported:
Basic	$	0.37	$	0.64
Diluted		0.34		0.60
Pro forma:
Basic	$	0.35	$	0.62
Diluted		0.34		0.59

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Prior to the adoption of SFAS No. 123(R) on January 1, 2006, we did not assume the capitalization of any stock-based compensation in our SFAS No. 123 pro forma net income. As a result, no stock-based compensation expense is reflected as being capitalized in the table above. Beginning in 2006, an appropriate portion of stock-based compensation associated with our employees involved 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 and six months ended June 30, 2006 was to decrease net income by approximately $1.9 million and $3.8 million, respectively. The effect on earnings per share for the three months ended June 30, 2006 was a decrease of $0.02 per both basic and diluted share, and for the six months ended June 30, 2006 was a decrease of $0.03 per both basic and diluted share. Additionally, cash flow from operations was lower and cash flow from financing activities was higher by approximately $4.3 million and $10.2 million for the three and six months ended June 30, 2006, respectively, associated with the tax benefits for tax deductions in excess of recognized compensation expenses that is 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.


	Six months ended			Year ended
	June 30, 2006			December 31, 2005
Weighted average fair value of options granted		$12.65		$	6.94
Risk free interest rate		4.48	%		3.80	%
Expected life		4.9 to 6.9 years		5 years
Expected volatility		41.9	%		42.6	%
Dividend yield		—			—

The following is a summary of our stock option and SARs activity for the six months ended June 30, 2006 and the year ended December 31, 2005:


	Six Months Ended					Year Ended
	June 30, 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		441,088			26.40		2,483,254			16.29
Exercised		(1,159,945	)		4.96		(1,797,146	)		5.37
Forfeited		(343,863	)		10.73		(160,350	)		8.86

Outstanding at end of period		8,343,352			9.37		9,406,072			8.07


Exercisable at end of period		2,865,577		$	4.60		2,509,635		$	4.50

The total intrinsic value of options exercised during the six months ended June 30, 2006 and the year ended December 31, 2005 was approximately $28.0 million and $24.8 million, respectively. The aggregate intrinsic value of stock options and SARs outstanding at June 30, 2006 was approximately $186.1 million and these options and SARs have a weighted-average remaining contractual life of 6.6 years. The aggregate intrinsic value of Options exercisable at June 30, 2006 was approximately $77.6 million and these Options 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 non-vested Options as of June 30, 2006, and the changes during the six months ended June 30, 2006, is presented below:


				Weighted-Average
				Grant-Date
Non-vested Options	Shares			Fair Value
Non-vested at January 1, 2006		6,896,437		$	4.25
Granted		441,088			12.65
Vested		(1,516,475	)		2.59
Forfeited		(343,275	)		4.96

Non-vested at June 30, 2006		5,477,775			5.34

As of June 30, 2006, there was $15.0 million of total compensation cost to be recognized in future periods related to non-vested 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 six months ended June 30, 2006 and year ended December 31, 2005 was $5.8 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 $9.9 million for the six months ended June 30, 2006 and $8.6 million for the year ended December 31, 2005.

We have issued 2,366,229 shares of restricted stock pursuant to the 2004 Plan and have recorded deferred compensation expense of $24.6 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 June 30, 2006, there was $14.2 million of unrecognized compensation expense related to non-vested restricted stock grants. The unrecognized compensation cost is expected to be recognized over a weighted-average period of 3.1 years.

A summary of the status of our non-vested restricted stock grants as of June 30, 2006, and the changes during the six months ended June 30, 2006, is presented below:


				Weighted-Average
				Grant-Date
Non-vested Restricted Stock Grants	Shares			Fair Value
Non-vested at January 1, 2006		2,014,000		$	10.15
Granted		46,229			26.02
Vested		(202,015	)		10.25
Forfeited		(170,675	)		10.26

Non-vested at June 30, 2006		1,687,539			10.56

7. 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 June 30, 2006 and 2005 was $319,000 and $44,000, respectively, and for the six months ended June 30, 2006 and 2005 was $559,000 and $331,000, respectively. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which as of June 30, 2006 was $11.5 million, plus $11.8 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

In May 2006, we invested $1.5 million in a petroleum coke-to-ammonia project that is in the development stage. We have also committed to invest an additional $1.5 million, all of which may later be redeemed, with a return, or converted to equity after construction financing for the project has been obtained. If built, we plan to take up to 100% of the CO₂ produced from this plant. Genesis has also invested in this project, with its total commitment not to exceed $1.0 million.

Oil Sales and Transportation Services

Prior to September 2004, including the period prior to our investment in Genesis, we sold certain of our oil production to Genesis. Beginning in September 2004, we discontinued most of our direct sales to Genesis and began to transport our crude oil using Genesis’ common carrier pipeline to a sales point where it is sold to third party purchasers. For these transportation services, we pay Genesis a fee for the use of their pipeline and trucking services. In the first six months of 2006 and 2005, we expensed $2.1 million and $2.0 million, respectively, for these transportation services. Denbury received other miscellaneous payments from Genesis for the six months ended June 30, 2006 and 2005, including $60,000 in each period of director fees for certain executive officers of Denbury that are board members of Genesis, and $420,000 and $255,000, 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. 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 June 30, 2006, we had $6.2 million of capital lease obligations recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $602,000 was current. At December 31, 2005, we had $6.4 million of capital lease obligations recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $574,000 was current.

CO₂ Volumetric Production Payments

During 2003 through 2005, we sold 280.5 Bcf of CO₂ to Genesis under volumetric production payment agreements. 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 June 30, 2006 and December 31, 2005, $35.1 million and $37.1 million, respectively, was recorded as deferred revenue of which $4.1 million was included in current liabilities at June 30, 2006 and December 31, 2005. We recognized deferred revenue of $1.1 million and $0.7 million during the three months ended June 30, 2006 and 2005 and $2.0 and $1.3 million for the six months ended June 30, 2006 and 2005, 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 $1.2 million and $0.8 million in revenue for the three months ended June 30, 2006 and 2005 and $2.2 million and $1.5 million for the six months ended June 30, 2006 and 2005, respectively.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2006		2005			2006		2005
Revenues	$	233,343	$	257,144		$	496,945	$	513,744
Cost of sales		224,707		252,129			481,465		503,873
Other expenses		5,192		4,263			9,445		6,631
Income (loss) from discontinued operations		—		(9	)		—		273

Net income	$	3,444	$	743		$	6,035	$	3,513


	June 30,		December 31,
	2006		2005
Current assets	$	114,662	$	90,449
Non-current assets		92,991		91,328

Total assets	$	207,653	$	181,777


Current liabilities	$	105,804	$	92,611
Non-current liabilities		12,526		955
Partners’ capital		89,323		88,211

Total liabilities and partners’ capital	$	207,653	$	181,777

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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. Prior to 2005, we 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. As of June 30, 2006, the only derivative contracts we have in place relate to the $250 million acquisition that closed January 31, 2006, on which we entered into contracts to cover 100% of the estimated proved production for three years at the time we signed the purchase and sale agreement in November 2005. 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 (Income)” included in our Condensed Consolidated Statements of Operations:


	Three Months					Six Months
	Ended June 30,					Ended June 30,
(In Thousands)	2006		2005			2006		2005
Settlements of derivative contracts not designated as hedges — Oil	$	2,212	$	—		$	2,980	$	—
Settlements of derivative contracts not designated as hedges — Gas		—		1,776			—		2,875
Reclassification of accumulated other comprehensive income balance		—		1,761			—		3,575
Fair value adjustments to derivative contracts		9,317		(4,562	)		20,179		346

Commodity derivative expense (income)	$	11,529	$	(1,025	)	$	23,159	$	6,796


Derivative Oil Contracts at June 30, 2006
					Fair Value at
	NYMEX Contract Prices Per Bbl				June 30, 2006
Type of Contract and Period	Bbls/d		Swap Price		(In Thousands)
Swap Contracts
July 2006 - Dec. 2006		2,200	$	59.65	$	(7,071	)
Jan. 2007 - Dec. 2007		2,000		58.93		(11,747	)
Jan. 2008 - Dec. 2008		2,000		57.34		(10,744	)

At June 30, 2006, our derivative contracts were recorded at their fair value, which was a liability of $29.6 million.

9. 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 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


	June 30, 2006
	Denbury		Denbury
	Resources Inc.		Onshore, LLC							Denbury
	(Parent and		(Issuer and		Guarantor					Resources Inc.
Amounts in thousands	Co-Obligor)		Co-Obligor)		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	375,011	$	144,019	$	4,109	$	(371,820	)	$	151,319
Property and equipment		—		1,693,032		36		—			1,693,068
Investment in subsidiaries (equity method)		595,063		—		594,236		(1,178,367	)		10,932
Other assets		154,189		12,281		155		(152,476	)		14,149

Total assets	$	1,124,263	$	1,849,332	$	598,536	$	(1,702,663	)	$	1,869,468


Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	533,758	$	3,174	$	(371,820	)	$	165,112
Long-term liabilities		150,000		732,270		299		(152,476	)		730,093
Stockholders’ equity		974,263		583,304		595,063		(1,178,367	)		974,263

Total liabilities and stockholders’ equity	$	1,124,263	$	1,849,332	$	598,536	$	(1,702,663	)	$	1,869,468


	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


	Three Months Ended June 30, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and		Guarantor						Resources Inc.
Amounts in thousands	Co-Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	2,781		$	190,466	$	—		$	—		$	193,247
Expenses		2,858			116,791		329			—			119,978

Income (loss) before the following:		(77	)		73,675		(329	)		—			73,269
Equity in net earnings of subsidiaries		44,342			—		44,808			(88,831	)		319

Income before income taxes		44,265			73,675		44,479			(88,831	)		73,588
Income tax provision		3			29,186		137			—			29,326

Net income	$	44,262		$	44,489	$	44,342		$	(88,831	)	$	44,262


	Three Months Ended June 30, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and		Guarantor						Resources Inc.
Amounts in thousands	Co-Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	127,983	$	—		$	—		$	127,983
Expenses		41			67,198		252			—			67,491

Income (loss) before the following:		(41	)		60,785		(252	)		—			60,492
Equity in net earnings of subsidiaries		40,697			—		40,868			(81,521	)		44

Income before income taxes		40,656			60,785		40,616			(81,521	)		60,536
Income tax provision (benefit)		(16	)		19,961		(81	)		—			19,864

Net income	$	40,672		$	40,824	$	40,697		$	(81,521	)	$	40,672

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Operations (continued)


	Six Months Ended June 30, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and		Guarantor						Resources Inc.
Amounts in thousands	Co-Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	5,594		$	366,559	$	—		$	—		$	372,153
Expenses		5,761			220,855		760			—			227,376

Income (loss) before the following:		(167	)		145,704		(760	)		—			144,777
Equity in net earnings of subsidiaries		88,201			—		89,152			(176,794	)		559

Income before income taxes		88,034			145,704		88,392			(176,794	)		145,336
Income tax provision (benefit)		(6	)		57,111		191			—			57,296

Net income	$	88,040		$	88,593	$	88,201		$	(176,794	)	$	88,040


	Six Months Ended June 30, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and		Guarantor						Resources Inc.
Amounts in thousands	Co-Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	241,345	$	—		$	—		$	241,345
Expenses		82			136,684		479			—			137,245

Income (loss) before the following:		(82	)		104,661		(479	)		—			104,100
Equity in net earnings of subsidiaries		70,789			—		71,210			(141,668	)		331

Income before income taxes		70,707			104,661		70,731			(141,668	)		104,431
Income tax provision (benefit)		(32	)		33,782		(58	)		—			33,692

Net income	$	70,739		$	70,879	$	70,789		$	(141,668	)	$	70,739

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Cash Flows


	Six Months Ended June 30, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC							Denbury
	(Parent and			(Issuer and			Guarantor				Resources Inc.
Amounts in thousands	Co-Obligor)			Co-Obligor)			Subsidiaries		Eliminations		Consolidated
Cash flow from operations	$	(140,340	)	$	348,822		$	447	$	—	$	208,929
Cash flow from investing activities		—			(553,179	)		—		—		(553,179	)
Cash flow from financing activities		140,340			69,633			—		—		209,973

Net increase (decrease) in cash		—			(134,724	)		447		—		(134,277	)
Cash, beginning of period		1			164,408			680		—		165,089

Cash, end of period	$	1		$	29,684		$	1,127	$	—	$	30,812


	Six Months Ended June 30, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and			(Issuer and			Guarantor					Resources Inc.
Amounts in thousands	Co-Obligor)			Co-Obligor)			Subsidiaries			Eliminations		Consolidated
Cash flow from operations	$	(4,661	)	$	159,430		$	245		$	—	$	155,014
Cash flow from investing activities		—			(177,138	)		(6	)		—		(177,144	)
Cash flow from financing activities		4,661			9,746			—			—		14,407

Net increase (decrease) in cash		—			(7,962	)		239			—		(7,723	)
Cash, beginning of period		1			32,881			157			—		33,039

Cash, end of period	$	1		$	24,919		$	396		$	—	$	25,316

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 five primary field offices located in Houma, Louisiana; Laurel, Mississippi; McComb, Mississippi; Brandon, Mississippi; and Cleburne, Texas.

Overview

Operating results. Earnings and cash flow from operations were at near-record levels for the second quarter and first half of 2006, primarily as a result of high commodity prices. We set a new quarterly production level during the second quarter of 2006, averaging 37,474 BOE/d, assisted in part by the acquisition which closed January 31, 2006, which added 2,199 BOE/d to our second quarter production average, supplemented by higher production in our tertiary operations, and in the Barnett Shale, and higher natural gas production in Louisiana following several exploratory successes during 2005.

Net income for the second quarter of 2006 was $44.3 million as compared to net income of $40.7 million during the second quarter of 2005, relatively close bottom lines, but with a combination of several positive and negative factors affecting these results. In addition to the aforementioned high oil and natural gas prices and record production, which contributed to higher net income, we also capitalized approximately $2.7 million of interest expense in the second quarter of 2006 primarily related to the unevaluated properties associated with our 2006 acquisitions, reducing the overall increase in interest expense to 33%, even though average debt levels were 87% higher in the second quarter of 2006 than in the comparable period of 2005. Overall industry costs continue to increase, the primary reason for record, or near record, operating costs and depreciation and depletion rates per BOE in the second quarter of 2006. Operating expenses were also impacted by higher energy costs (electrical and fuel charges) and our continuing emphasis on tertiary operations. During the second quarter of 2006, we also incurred a $9.3 million mark-to-market pre-tax charge to earnings ($5.6 million after tax) as rising oil prices reduced the value of the Company’s oil derivative contracts put in place to cover our January 2006 acquisition. Further, we expensed approximately $5.3 million related to the modification of the vesting terms of certain restricted stock and stock options previously granted to Mr. Worthey, former Senior Vice-President of Operations, associated with his departure during the second quarter of 2006. Additionally, we booked stock compensation expenses related to the adoption of SFAS No. 123(R) as of January 1, 2006, which for the second quarter of 2006 resulted in a non-cash charge of approximately $1.8 million to general and administrative expense, approximately $0.3 million to lease operating expense and approximately $0.3 million to capitalized oil and gas properties. Lastly, our income tax expense increased primarily as a result of high oil prices causing enhanced oil recovery credits to become unavailable during 2006.

Net income for the first six months of 2006 was $88.0 million as compared to $70.7 million of net income during the first six months of 2005. The incremental net income during the first half of 2006 was attributable to most of the factors noted above related to the respective second quarters, principally higher commodity prices and higher production, partially offset by higher costs.

In addition to inflationary costs in our industry, we are experiencing more and more delays in obtaining goods and services. This industry trend has 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 completing our planned projects, which will likely also cause delays in achieving our anticipated production targets. See “Results of Operations” for a more thorough discussion of our operating results.

DENBURY RESOURCES INC.

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

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 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 our focus on these types of operations.

Oil production from our tertiary operations increased to an average of 10,375 BOE/d in the second quarter of 2006, a 10% increase over the second quarter of 2005 tertiary production level of 9,417 BOE/d, and a 6% increase over the first quarter 2006 production levels. Recent 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 field, so we do not believe the reserves estimates have been negatively affected at all; however, 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. Overall industry delays in obtaining goods and services have impacted our ability to complete certain projects on time and consequently have affected our ability to meet our tertiary production forecast.

Recent 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 have begun our initial tertiary development work at Tinsley Field, consisting primarily of planning, land and engineering work, with more extensive development and facility construction 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 adjusted purchase price for these three properties was approximately $250 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 (repaid in April 2006 with proceeds from our recent equity offering). 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.

During May 2006, we purchased the Delhi Holt-Bryant Unit (“Delhi”) in northern Louisiana for $50 million, plus a 25% reversionary interest to the seller after we have achieved $200 million in net operating revenue, as defined. Delhi is also a future potential CO₂ tertiary oil flood candidate, one that will require construction of a CO₂ pipeline before flooding can commence, which will likely be an extension of the larger, new CO₂ pipeline currently planned from Jackson Dome to Tinsley Field. We hope to have this CO₂ line installed within the next two to three years, with initial oil production from tertiary operations currently anticipated during 2010. Currently, there are neither significant oil production nor proved oil reserves at Delhi.

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 then current borrowings under our bank credit facility, which were $120 million as of that date, the majority of which was incurred to partially fund our $250 million acquisition of three properties in January 2006.

Capital Resources and Liquidity

Our current 2006 capital budget, excluding any potential acquisitions, is $550 million, which at commodity futures prices as of the end of July 2006, appears to be $25 million to $50 million more than our anticipated cash flow from operations, depending on commodity price fluctuations. Our capital budget was increased by approximately $50 million following our April 2006 equity sale and reduction in overall debt in order to compensate for rising costs and to purchase certain equipment for 2007 with long lead times. The excess of capital expenditures over our cash flow from operations

DENBURY RESOURCES INC.

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

will be funded by our bank credit line. 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, 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, and we expect to further increase our borrowing base this fall, potentially by another $200 million, subject to bank approval and terms that are acceptable to us. This increased borrowing base will give 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 June 30, 2006, we had outstanding $225 million (principal amount) of 7.5% subordinated notes due 2013, $150 million (principal amount) of 7.5% subordinated notes due 2015, approximately $70.0 million of bank debt, and $6.2 million of capital leases.

Sources and Uses of Capital Resources

During the first six months of 2006, we incurred $250.1 million on oil and natural gas exploration and development expenditures, $28.2 million on CO₂ exploration and development expenditures, and approximately $314.3 million on property acquisitions, for total capital expenditures of approximately $592.6 million. Our exploration and development expenditures included approximately $102.1 million spent on drilling, $17.0 million spent on geological, geophysical and acreage expenditures and $131.0 million incurred on facilities and recompletion costs. We funded these expenditures with $208.9 million of cash flow from operations, $125 million of equity, $70.0 million of bank borrowings, and a $14.6 million increase in our accrued capital expenditures, with 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 $236.6 million for the first six months of 2006, while cash flow from operations for the same period, the GAAP measure, was $208.9 million.

During the first six months of 2005, we spent $138.9 million on oil and natural gas exploration and development expenditures, $35.1 million on CO₂ exploration and development expenditures (including $22.4 million on our CO₂ pipeline being constructed to East Mississippi), and approximately $68.5 million on property acquisitions for total capital expenditures of approximately $242.5 million. Our exploration and development expenditures included approximately $64.9 million incurred on drilling, $11.6 million spent on geological, geophysical and acreage expenditures and $62.4 million incurred for facilities and recompletion costs. We funded these expenditures with $155.0 million of cash flow from operations and $10.0 million of net bank borrowings, with the balance funded from cash and other sources, including funds 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 June 30, 2006, consisted of $11.5 million of debt and $11.8 million in letters of credit) and we have delivery obligations to deliver CO₂ to our industrial customers. In June 2006, we extended our Plano, Texas office lease term by 10 years, to 2019. The total minimum lease payments under the lease are approximately $32 million during the 13 year period. Lease payments are payable monthly and are approximately $2 million per year initially and increase to approximately $2.7 million per year at the end of the term. The lease qualifies for operating lease treatment under GAAP. Our derivative contracts are discussed in Note 8 to the Unaudited Condensed Consolidated Financial Statements. Neither the amounts nor the terms of these non-balance sheet commitments or contingent obligations have changed significantly, other than the Plano, Texas office lease noted above, 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

DENBURY RESOURCES INC.

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

Arrangements — Commitments and Obligations” contained in our 2005 Form 10-K for further information regarding our commitments and obligations.

Results of Operations

CO₂ Operations

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 tertiary operating 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 issues.

We plan to drill three new CO₂ source wells during 2006. The first well drilled in early 2006 is currently awaiting hookup to facilities. Preliminary indications are that while 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. Our second well should reach total depth during August 2006 and should further significantly increase our productive capability, but is not expected to add significant incremental CO₂reserves. Our third well will commence after the second and is targeted to increase both our reserves and production. Drilling is expected to continue for the foreseeable future as our CO₂production capacity must continue to increase in order to meet our long-term oil production goals, and we are attempting to increase our proven CO₂reserves in order to further expand our tertiary operations. During the first half of 2006, our CO₂ production averaged 290 MMcf/d. We used 77% of this, or 223 MMcf/d, in our tertiary operations, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.

Oil production from our tertiary operations increased to an average of 10,375 BOE/d in the second quarter of 2006, a 10% increase over the second quarter of 2005 tertiary production level of 9,417 BOE/d, and a 6% increase over the first quarter of 2006 tertiary production levels. Recent 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 field, so we do not believe the reserves estimates have been negatively affected at all; however, 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. Overall industry delays in obtaining goods and services have impacted our ability to complete certain projects on time and consequently have affected our ability to meet our tertiary production forecast.


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

Brookhaven		—		—		—		125		547		798
Little Creek & Lazy Creek		3,709		3,847		3,357		3,210		3,006		3,056
Mallalieu (East and West)		4,235		4,582		4,565		5,562		5,219		5,385
McComb & Olive		700		988		928		1,011		932		1,062
Smithdale		—		—		—		31		54		74

Total tertiary oil production		8,644		9,417		8,850		9,939		9,758		10,375

We spent approximately $0.20 per Mcf to produce our CO₂during the first half of 2006, up from the 2005 six month average of $0.14 per Mcf, principally as a result of higher oil commodity prices, which results in higher royalty payments, and higher labor, utilities and equipment rental expense. Our estimated total cost per thousand cubic feet of CO₂ during the first half of 2006 was approximately $0.29, after inclusion of depreciation and amortization expense, up from the 2005 average of $0.21 per Mcf for these same reasons. On a quarterly basis, we spent approximately $0.21 per Mcf to produce our CO₂during the second quarter of 2006, higher than the 2005 second quarter average of $0.15 per Mcf, consistent with

DENBURY RESOURCES INC.

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

the six month trends. Our estimated total cost per thousand cubic feet of CO₂ during the second quarter of 2006 was approximately $0.30, after inclusion of depreciation and amortization expense.

For the first half of 2006, our operating costs for our tertiary properties averaged $16.26 per BOE, up significantly from the $10.58 per BOE average in the first half of 2005 and our 2005 annual average of $12.00 per BOE. The higher costs were a result of higher CO₂ costs (see prior paragraph), higher fuel and energy costs (which represent almost 37% of our total tertiary operating costs excluding the cost of CO₂), higher rental payments on leased equipment, and general cost inflation in the industry, partially offset by higher production levels. In addition, we incurred approximately $1.3 million, or approximately $1.33 per BOE during the second quarter of 2006, for operating expenses at three new tertiary floods where we commenced operations but have not yet seen any production response (response is expected late in 2006 or early 2007).

Operating Results

As summarized in the “Overview” section above and discussed in more detail below, higher commodity prices, and higher production more than offset higher expenses, resulting in near-record quarterly earnings and cash flow from operations. Included in the first half of 2006 net income is the effect of approximately $11.3 million ($9.2 million after tax) of non-cash charges related to the adoption of SFAS No. 123(R) as of January 1, 2006, relating to certain stock-based compensation that was previously only reflected as a footnote disclosure and not recorded in the financial statements (See Note 6 to the Unaudited Condensed Consolidated Financial Statements).


	Three Months Ended					Six Months Ended
	June 30,					June 30,
Amounts in thousands, except per share amounts	2006			2005		2006			2005
Net income	$	44,262		$	40,672	$	88,040		$	70,739
Net income per common share — basic		0.38			0.37		0.77			0.64
Net income per common share — diluted		0.36			0.34		0.72			0.60

Adjusted cash flow from operations (see below)	$	128,793		$	81,951	$	236,642		$	151,362
Net change in assets and liabilities relating to operations		(22,376	)		6,434		(27,713	)		3,652

Cash flow from operations (1)	$	106,417		$	88,385	$	208,929		$	155,014


(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 half of 2006, we used cash to fund a net increase in our other working capital items, primarily a decrease in our payables. Conversely, during the first six months of 2005, cash increased due to an increase in payables, partially offset by an increase in our receivables.

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 second quarters and first six months of 2006 and 2005 are included in the following table.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Average daily production volumes
Bbls/d		23,362			20,623			22,790			20,444
Mcf/d		84,671			59,080			82,076			57,929
BOE/d (1)		37,474			30,469			36,469			30,099

Operating revenues (thousands)
Oil sales	$	136,118		$	89,169		$	249,559		$	168,351
Natural gas sales		53,286			36,603			115,388			68,437

Total oil and natural gas sales	$	189,404		$	125,772		$	364,947		$	236,788


Oil and gas derivative contracts (2) (thousands)
Cash expense on settlement of derivative contracts	$	(2,212	)	$	(1,776	)	$	(2,980	)	$	(2,875	)
Non-cash derivative (expense) income		(9,317	)		2,801			(20,179	)		(3,921	)

Total income (expense) from oil and gas derivative contracts	$	(11,529	)	$	1,025		$	(23,159	)	$	(6,796	)


Operating expenses (thousands)
Lease operating expenses	$	41,751		$	26,757		$	77,923		$	49,719
Production taxes and marketing expenses (3)		9,436			6,582			17,523			12,708

Total production expenses	$	51,187		$	33,339		$	95,446		$	62,427


CO₂ sales and transportation fees (4)	$	2,374		$	1,517		$	4,362		$	3,247
CO₂ operating expenses		785			445			1,430			791

CO₂ operating margin	$	1,589		$	1,072		$	2,932		$	2,456


Unit prices — including impact of derivative settlements
Oil price per Bbl	$	62.99		$	47.51		$	59.78		$	45.50
Gas price per Mcf		6.92			6.48			7.77			6.25

Unit prices — excluding impact of derivative settlements
Oil price per Bbl	$	64.03		$	47.51		$	60.50		$	45.50
Gas price per Mcf		6.92			6.81			7.77			6.53

Oil and gas operating revenues and expenses per BOE (1):
Oil and natural gas revenues	$	55.54		$	45.36		$	55.29		$	43.46


Oil and gas lease operating expenses	$	12.24		$	9.65		$	11.80		$	9.12
Oil and gas production taxes and marketing expense		2.77			2.37			2.65			2.33

Total oil and gas production expenses	$	15.01		$	12.02		$	14.45		$	11.45


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

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

(3)		Includes transportation expense — Genesis.

(4)		Includes deferred revenue of $1.1 million and $0.7 million for the three months ended June 30, 2006 and 2005, respectively, and $2.0 and $1.3 million for the six months ended June 30, 2006 and 2005, respectively, associated with volumetric production payments with Genesis. Also includes transportation income from Genesis of $1.2 million and $0.8 million for the three months ended June 30, 2006 and 2005, respectively, and $2.2 million and $1.5 million for the six months ended June 30, 2006 and 2005, respectively.

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 and second quarters of 2006 is listed in the following table.


	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Second
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Operating Area	2005		2005		2005		2005		2006		2006
Mississippi — non-CO2 floods		13,057		12,788		10,998		11,475		12,455		12,633
Mississippi — CO2 floods		8,644		9,417		8,850		9,939		9,758		10,375
Onshore Louisiana		6,710		5,791		5,169		6,992		8,349		8,623
Barnett Shale		1,313		2,052		2,150		3,048		3,953		4,621
Alabama		—		37		126		141		917		1,213
Other ⁽¹⁾		—		384		52		54		22		9

Total Company		29,724		30,469		27,345		31,649		35,454		37,474


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

As outlined in the above table, production in the second quarter of 2006 increased 23% (7,005 BOE/d) over second quarter of 2005 levels and 6% over the first quarter 2006 levels, and was up 21% during the comparable first six month periods. Of this increase, the January 2006 acquisition contributed approximately 2,199 BOE/d of the increase in the 2006 second quarter average production (1,097 BOE/d to the Mississippi – non-CO₂ floods and 1,102 BOE/d to Alabama in the above table) and approximately 2/3rds of that amount (two months production) during the first quarter of 2006. In addition, our onshore Louisiana production for the first six months of 2006 increased 2,239 BOE/d (36% increase) over the prior years first half levels, due primarily to 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 during the first half of 2006 increased 2,605 BOE/d (155% increase) over first half 2005 levels, also as a result of increased drilling activity, with 40 to 50 wells planned in 2006. Production in the Mississippi – non-CO₂ floods area changed only modestly during the last three quarters (before giving effect to the January 2006 acquisition related increase noted above), following modest declines early in 2005. See “CO₂ Operations” above for a discussion of the tertiary related production.

Our production for the second quarter of 2006 was weighted toward oil (62%), slightly less than the percentage of oil production (68%) during the second quarter of 2005, as a result of the recent increases in natural gas production in the Barnett Shale area and Louisiana.

Oil and Natural Gas Revenues: Oil and natural gas revenues for the second quarter of 2006 increased $63.6 million, or 51%, from revenues in the comparable quarter of 2005, as both commodity prices and production were higher. When comparing the respective six month periods, revenues increased $128.2 million, or 54%, for the same reasons. Cash payments of $2.2 million on our commodity derivative contracts were not significant to either period as our derivative contracts represented less than 10% of our total production for both comparative periods (excluding price floors in 2005 which had no potential cash payment). See “Market Risk Management” for additional information regarding our hedging activities.

The 23% increase in production in the second quarter of 2006 increased oil and natural gas revenues, when comparing the two second quarters, by $28.9 million, while the increase in overall commodity prices increased revenue by $34.7 million, or 28%. On a six month basis, the 21% increase in production in the first half of 2006 increased oil and natural gas revenues, when comparing the two first six months, by $50.1 million, while the increase in overall commodity prices increased revenue by $78.0 million, or 33%. Although both oil and natural gas prices were higher in the current year periods than in the 2005 periods, oil prices increased significantly more than natural gas prices. Our realized oil prices (excluding hedges) increased by 35% between the second quarters of 2005 and 2006 and by 33% between the

DENBURY RESOURCES INC.

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

comparable six month periods, while our realized natural gas prices (excluding hedges) increased by only 2% between the second quarters of 2005 and 2006 and by 19% between the comparable six month periods. On a combined BOE basis, commodity prices were 22% higher for the comparative second quarters and 27% higher for the comparative first six months of 2005 and 2006.

The differentials between our net realized oil prices (excluding commodity derivative contracts) and NYMEX prices were modestly higher in the first half of 2006 than in the first half of 2005, both of which were also similar to the fourth quarter of 2005 differentials. Our average oil differential for the first half of 2006 was approximately $6.58 per Bbl as compared to $6.11 per Bbl during the first half of 2005 and an average of $6.17 per Bbl during the fourth quarter of 2005. The higher overall differential in the first half of 2006 was primarily related to higher sour crude differentials prices relative to NYMEX during the period. These trends are difficult to accurately forecast.

Our natural gas differentials relative to NYMEX improved in the first half of 2006 compared to the first half of 2005. The variance improved during 2006, primarily due to decreasing natural gas prices, particularly during the first quarter of 2006, and to a lesser degree during the second 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 half of 2006 was a positive variance of approximately $0.49 per Mcf, as compared to a negative variance of $0.17 per Mcf during the first half 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 six months and second 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 results and approximately $348,000 to second quarter lease operating expense, representing the stock compensation expense pertaining to operating personnel.

During the second quarter of 2006, operating costs averaged $12.24 per BOE, up from $9.65 per BOE in the second quarter of 2005, and up from the $11.34 per BOE in the first quarter of 2006. Operating expenses on our tertiary operations increased from $9.4 million in the second quarter of 2005 to $16.4 million during the second 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 $4.6 million during the second quarter of 2006. The trends were similar when comparing the respective first half periods.

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

DENBURY RESOURCES INC.

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

General and Administrative Expenses

General and administrative (“G&A”) expenses increased 143% between the respective second quarters and 96% between the respective first six months, as set forth below:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Net G&A expense (thousands)
Gross G&A expenses	$	26,704		$	14,747		$	47,471		$	29,125
State franchise taxes		282			309			694			618
Operator labor and overhead recovery charges		(10,625	)		(7,868	)		(19,961	)		(14,854	)
Capitalized exploration costs		(1,787	)		(1,196	)		(3,763	)		(2,402	)

Net G&A expense	$	14,574		$	5,992		$	24,441		$	12,487

Average G&A cost per BOE	$	4.27		$	2.16		$	3.70		$	2.29
Employees as of June 30		550			417			550			417

Gross G&A expenses increased $11.9 million, or 81%, between the respective second quarters and $18.3 million or 63% between the respective first six months. The single biggest increase was a $5.3 million charge to earnings in the second quarter of 2006 related to the modification of the vesting terms of certain restricted stock and stock options previously granted to Mr. Worthey, former Senior Vice-President of Operations, associated with his departure. The adoption of SFAS No. 123(R) in January 2006 further increased net G&A expense by approximately $3.5 million during the first six months ($1.8 million during the second quarter of 2006), 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 quarterly 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). G&A also increased along with higher compensation costs due to additional employees, associated expenses and wage increases. From June 30, 2005 to June 30, 2006, we had a net increase of 32% in our employee count related to our acquisitions and increased activity level. In addition, due to increased competitive pressures in the industry, our wages are increasing at a rate higher than general inflation and we expect this trend to continue. As such, we granted a 5% pay raise to all employees effective July 1, 2006.

The increase in gross G&A was offset in part by an increase in operator overhead recovery charges in the second quarter and first six months of 2006. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of our acquisitions and incremental drilling and development activity during the second quarter and first six months of 2006, the amount we recovered as operator overhead charges increased by 35% between the second quarters of 2005 and 2006 and increased by 34% between the first six months of 2005 and 2006. The operator overhead recovery charges also increased as a result of the allocation to operations of stock compensation cost related to the adoption of SFAS No. 123(R). Capitalized exploration costs also increased by 49% between the second quarters of 2005 and 2006 and increased by 57% between the first six months of 2005 and 2006 as a result of increased compensation costs, most of which relates to stock based compensation related to the adopted of SFAS No. 123(R).

The net effect was a 143% increase in net G&A expense between the respective second quarters and a 96% increase between the first six months of 2006 and 2005. On a per BOE basis, G&A costs increased 98% in the second quarter of 2006 as compared to the second quarter of 2005, and increased 62% for the comparative first six months of 2006 and 2005, both lower percentage increases than the increase in gross costs as a result of the higher production levels.

DENBURY RESOURCES INC.

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

Interest and Financing Expenses


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Amounts in thousands, except per BOE amounts	2006			2005			2006			2005
Cash interest expense	$	8,225		$	4,504		$	16,493		$	9,037
Non-cash interest expense		261			204			521			409
Less: Capitalized interest		(2,735	)		(373	)		(3,009	)		(635	)

Interest expense	$	5,751		$	4,335		$	14,005		$	8,811

Interest and other income	$	1,469		$	694		$	2,844		$	1,310

Average net cash interest expense per BOE (1)	$	1.18		$	1.24		$	1.61		$	1.30
Average interest rate (2)		7.4	%		7.6	%		7.4	%		7.6	%
Average debt outstanding	$	443,786		$	237,113		$	445,361		$	239,153


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

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

Interest expense increased $1.4 million, or 33%, when comparing the second quarters of 2005 and 2006, primarily due to higher average debt levels. Debt levels were unusually low in the first half of 2005 following the sale of our offshore properties in mid-2004. Conversely, debt levels increased in the first quarter of 2006 following the $250 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”), but an additional $50 million was subsequently borrowed to fund the Delhi acquisition (see “Overview – Recent Acquisitions”) and an additional $20 million for general working capital, leaving us with total bank debt of $70.0 million as of June 30, 2006. Our interest expense was reduced by $2.7 million during the second quarter of 2006 as we capitalized interest on our significant unevaluated properties, primarily related to the two recent acquisitions.

Depletion, Depreciation and Amortization


	Three Months Ended				Six Months Ended
	June 30,				June 30,
Amounts in thousands, except per BOE amounts	2006		2005		2006		2005
Depletion and depreciation of oil and natural gas properties	$	32,199	$	22,126	$	61,516	$	41,536
Depletion and depreciation of CO₂ assets		1,891		1,168		3,680		2,374
Asset retirement obligations		615		522		1,186		843
Depreciation of other fixed assets		1,447		589		2,513		1,180

Total DD&A	$	36,152	$	24,405	$	68,895	$	45,933

DD&A per BOE:
Oil and natural gas properties	$	9.62	$	8.17	$	9.50	$	7.78
CO₂ assets and other fixed assets		0.98		0.63		0.94		0.65

Total DD&A cost per BOE	$	10.60	$	8.80	$	10.44	$	8.43

Our depletion, depreciation and amortization (“DD&A”) rate on a per BOE basis increased 20% between the respective second quarters and increased 24% between the respective first six months, primarily due to rising costs. We allocated approximately $124 million of our $250 million January 2006 acquisition and virtually all of the $50 million Delhi acquisition to unevaluated properties to reflect the significant probable and possible reserves that we considered to be part of these acquisitions. As a result, these acquisitions did not materially affect our overall DD&A rate, as the amount

DENBURY RESOURCES INC.

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

included in our full cost pool was a cost per BOE relatively consistent with our overall DD&A rate. We booked approximately 3.2 MMBbls of incremental oil reserves related to our tertiary operations during the first half 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 first half 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 half of 2006 as compared to the comparative first six months in 2005 as a result of the Free State CO₂ pipeline which went into service late in the first quarter, the additional costs 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						Six Months Ended
	June 30,						June 30,
Amounts in thousands, except per BOE amounts and tax rates	2006			2005			2006			2005
Current income tax expense (benefit)	$	(2,349	)	$	4,354		$	7,437		$	9,636
Deferred income tax expense		31,675			15,510			49,859			24,056

Total income tax expense	$	29,326		$	19,864		$	57,296		$	33,692

Average income tax expense per BOE	$	8.60		$	7.16		$	8.68		$	6.18
Effective tax rate		39.9	%		32.8	%		39.4	%		32.3	%

Our income tax provision for the first half of 2006 and 2005 was based on an estimated statutory tax rate of 39%. For the first half of 2005, our net effective tax rate was 32.3%, 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 half 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 40%. Under the recently adopted accounting rules of 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 half 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. The current tax benefit recognized in the second quarter of 2006 is primarily a result of changes in estimated pre-tax income and changes in capital spending for intangible drilling costs, which resulted in the reclassification of tax expense between current and deferred taxes.

DENBURY RESOURCES INC.

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

Per BOE Data

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Per BOE data	2006			2005			2006			2005
Oil and natural gas revenues	$	55.54		$	45.36		$	55.29		$	43.46
Loss on settlements of derivative contracts		(0.65	)		(0.64	)		(0.45	)		(0.53	)
Lease operating expenses		(12.24	)		(9.65	)		(11.80	)		(9.12	)
Production taxes and marketing expenses		(2.77	)		(2.37	)		(2.65	)		(2.33	)

Production netback		39.88			32.70			40.39			31.48
CO₂ operating margin		0.47			0.39			0.44			0.45
General and administrative expenses		(4.27	)		(2.16	)		(3.70	)		(2.29	)
Net cash interest expense		(1.18	)		(1.24	)		(1.61	)		(1.30	)
Current income taxes and other		2.87			(0.13	)		0.33			(0.56	)
Changes in assets and liabilities relating to operations		(6.56	)		2.32			(4.20	)		0.67

Cash flow from operations		31.21			31.88			31.65			28.45
DD&A		(10.60	)		(8.80	)		(10.44	)		(8.43	)
Deferred income taxes		(9.29	)		(5.59	)		(7.55	)		(4.42	)
Non-cash hedging adjustments		(2.73	)		1.01			(3.06	)		(0.72	)
Changes in assets and liabilities and other non-cash items		4.39			(3.83	)		2.74			(1.90	)

Net income	$	12.98		$	14.67		$	13.34		$	12.98

DENBURY RESOURCES INC.

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

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 $70.0 million of bank debt outstanding as of June 30, 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.


	Expected Maturity Dates
							Carrying		Fair
Amounts in thousands	2009		2013		2015		Value		Value
Variable rate debt:
Bank debt	$	70,000	$	—	$	—	$	70,000	$	70,000
(The weighted-average interest rate on the bank debt at June 30, 2006 is 6.4%.)

Fixed rate debt:
7.5% subordinated debt due 2013, net of discount		—		225,000		—		223,688		223,875
(The interest rate on the subordinated debt is a fixed rate of 7.5%)
7.5% subordinated debt due 2015		—		—		150,000		150,000		149,250
(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 June 30, 2006, the only derivative contracts we have in place relate to the $250 million acquisition that closed on January 31, 2006, on which we entered into contracts to cover 100% of the estimated proved 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 June 30, 2006, our derivative contracts were recorded at their fair value, which was a net liability of approximately $29.6 million, an increase of approximately $20.2 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 commodity prices between December 31, 2005 and June 30, 2006.

Based on NYMEX crude oil futures prices at June 30, 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 June 30, 2006, we would expect to make future cash payments of $30.9 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 $16.9 million, and if futures prices were to increase by 10% we would expect to pay $44.9 million.

DENBURY RESOURCES INC.

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

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 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, or changes in 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.

During 2005 and the first half of 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, services and operational information by employees, and the failure by certain employees to properly report 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 substantially complete. As a result of our investigations, we have dismissed eight employees, taken disciplinary action against another employee, and terminated all future business with certain vendors. The estimated amount of improper vendor billings and payments and misuse of Company property and services 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 these matters have not, and 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 internal controls (see also Item 9A. “Controls and Procedures” – “Disclosure Controls and Procedures” contained in our 2005 Form 10-K for further information) and to improve our management practices and policies. We anticipate that various management changes that have been made, or are in the process of being made, will be combined with emphasis upon strengthening our internal controls through improved management oversight and enforcement of Company policies and procedures at the field level.

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. During the second quarter of 2006 we settled litigation that was disclosed in our 2005 Form 10-K, styled Harry Bourg Corporation vs. Exxon Mobile Corporations, et al. This settlement did not have any material impact on our results of operations or cash flows. There have been no other material developments in such legal proceedings since the filing of such Form 10-K.

Item 1.A. Risk Factors

Information with respect to the risk factors has been incorporated by reference from Item 1.A. of our Form 10-K for the year ended December 31, 2005. There have been no material changes to the risk factors since the filing of such Form 10-K.

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

ISSUER PURCHASES OF EQUITY SECURITIES


					(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
April 1 through 30, 2006		224	$	33.76		—		—
May 1 through 31, 2006		—		—		—		—
June 1 through 30, 2006		66,173		31.85		—		—
Total		66,397		31.86		—		—

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 and stock appreciation rights.

Item 3. Defaults Upon Senior Securities

None.

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

Denbury’s Annual Meeting of Stockholders was held on May 10, 2006 for the purposes of (1) electing seven directors, each to serve until their successor is elected and qualified, (2) to consider a stockholder proposal regarding performance-based options, and (3) to ratify the appointment by the audit committee of PricewaterhouseCoopers LLP as the Company’s independent auditor for 2006. At the record date, March 27, 2006, 115,383,847 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. Holders of 103,616,260 shares of common stock, representing approximately 90% of the total issued and outstanding shares of common stock, were present in person or by proxy at the meeting to cast their vote.

With respect to the election of directors, all seven nominees were re-elected. All of the directors are elected on an annual basis. The votes were cast as follows:


Nominees for Directors	For		Withheld
Ronald G. Greene		102,263,462		1,352,798
David I. Heather		103,448,929		167,331
Greg McMichael		103,449,136		167,124
Gareth Roberts		102,327,351		1,288,909
Randy Stein		103,390,595		225,665
Wieland F. Wettstein		101,920,895		1,695,365
Donald D. Wolf		103,370,668		245,592

The stockholder proposal regarding performance-based options was not approved. The votes were cast as follows:


For	Against		Abstentions		Broker Non-Votes
27,829,915		67,083,503		400,017		8,302,825

The appointment by the audit committee of PricewaterhouseCoopers LLP as the Company’s independent auditor for 2006 was approved. The votes were cast as follows:


For	Against		Abstentions		Broker Non-Votes
103,185,009		83,387		347,864		0

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits:


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.

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: August 7, 2006

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