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 September 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 October 31, 2006
Common Stock, $.001 par value		120,007,754

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares)


	September 30,			December 31,
	2006			2005
Assets
Current assets
Cash and cash equivalents	$	28,924		$	165,089
Accrued production receivables		67,000			65,611
Related party receivable — Genesis		386			1,312
Trade and other receivables		35,003			25,887
Deferred tax asset		10,624			41,284

Total current assets		141,937			299,183


Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		2,171,432			1,669,579
Unevaluated		241,736			46,597
CO₂ properties and equipment		252,680			210,046
Other		40,341			34,647
Less accumulated depletion and depreciation		(913,007	)		(804,899	)

Net property and equipment		1,793,182			1,155,970


Investment in Genesis		10,834			10,829
Deposits on property acquisitions		—			26,425
Other assets		15,691			12,662

Total assets	$	1,961,644		$	1,505,069


Liabilities and Stockholders’ Equity

Current liabilities
Accounts payable and accrued liabilities	$	113,746		$	104,840
Oil and gas production payable		51,131			41,821
Derivative liabilities		5,575			2,759
Deferred revenue — Genesis		4,070			4,070
Short-term capital lease obligations — Genesis		616			574

Total current liabilities		175,138			154,064


Long-term liabilities
Capital lease obligations — Genesis		5,402			5,870
Long-term debt		443,942			373,591
Asset retirement obligations		35,134			25,297
Derivative liabilities		9,405			6,624
Deferred revenue — Genesis		29,839			33,023
Deferred tax liability		215,536			170,758
Other		3,268			2,180

Total long-term liabilities		742,526			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; 120,237,661 and 115,038,531 shares issued at September 30, 2006 and December 31, 2005, respectively		120			115
Paid-in capital in excess of par		609,934			443,283
Retained earnings		442,909			295,575
Treasury stock, at cost, 408,669 and 340,337 shares at September 30, 2006 and December 31, 2005, respectively		(8,983	)		(5,311	)

Total stockholders’ equity		1,043,980			733,662

Total liabilities and stockholders’ equity	$	1,961,644		$	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						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006		2005
Revenues and other income
Oil, natural gas and related product sales
Unrelated parties	$	187,786		$	137,137		$	551,249	$	371,947
Related party — Genesis		12			1,411			1,496		3,389
CO₂ sales and transportation fees		2,687			2,594			7,049		5,841
Interest income and other		1,559			716			4,403		2,026

Total revenues		192,044			141,858			564,197		383,203


Expenses
Lease operating expenses		42,225			25,983			120,148		75,702
Production taxes and marketing expenses		8,611			5,995			23,997		16,713
Transportation expense — Genesis		1,138			1,023			3,275		3,013
CO₂ operating expenses		842			631			2,272		1,422
General and administrative		10,599			8,952			35,040		21,439
Interest, net of amounts capitalized of $3,731, $415, $6,740 and $1,049, respectively		5,009			4,507			19,014		13,318
Depletion, depreciation and amortization		41,188			24,340			110,083		70,273
Commodity derivative expense (income)		(12,375	)		11,818			10,784		18,614

Total expenses		97,237			83,249			324,613		220,494


Equity in net income (loss) of Genesis		157			(55	)		716		276


Income before income taxes		94,964			58,554			240,300		162,985

Income tax provision
Current income taxes		5,419			7,684			12,856		17,320
Deferred income taxes		30,251			12,324			80,110		36,380


Net income	$	59,294		$	38,546		$	147,334	$	109,285


Net income per common share — basic	$	0.50		$	0.34		$	1.27	$	0.98

Net income per common share — diluted	$	0.48		$	0.32		$	1.20	$	0.92

Weighted average common shares outstanding
Basic		117,917			112,159			115,864		111,466
Diluted		123,966			119,487			123,055		119,098

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Cash flow from operating activities:
Net income	$	59,294		$	38,546		$	147,334		$	109,285
Adjustments needed to reconcile to net cash flow provided by operations:
Depreciation, depletion and amortization		41,188			24,340			110,083			70,273
Non-cash derivative adjustments		(14,582	)		8,054			5,597			11,975
Deferred income taxes		30,251			12,324			80,110			36,380
Deferred revenue — Genesis		(1,178	)		(682	)		(3,183	)		(1,974	)
Stock based compensation		3,440			1,031			14,697			3,090
Income tax benefit from equity awards		—			3,242			—			8,676
Amortization of debt issue costs and other		570			491			987			1,003
Changes in assets and liabilities:
Accrued production receivables		3,697			(3,700	)		(463	)		(11,094	)
Trade and other receivables		(6,805	)		5,284			(12,745	)		(3,226	)
Other assets		1,400			—			(1,232	)		130
Accounts payable and accrued liabilities		17,280			(13,546	)		(6,488	)		2,272
Oil and gas production payable		1,003			955			9,309			5,253
Other liabilities		(193	)		(52	)		288			(742	)


Net cash provided by operations		135,365			76,287			344,294			231,301


Cash flow used for investing activities:
Oil and natural gas expenditures		(126,887	)		(72,020	)		(376,988	)		(210,900	)
Acquisitions of oil and gas properties		(1,315	)		(2,700	)		(315,650	)		(71,244	)
Change in accrual for capital expenditures		(1,617	)		10,878			12,995			19,868
Acquisitions of CO₂ assets and capital expenditures		(14,450	)		(14,751	)		(42,617	)		(49,869	)
Net purchases of other assets		(4,230	)		(1,057	)		(7,690	)		(4,156	)
Proceeds from oil and gas property sales		5,893			1,888			7,931			1,865
Deposits on acquisitions		126			—			26,425			4,507
Sales of short-term investments		—			2,000			—			57,133
Increase in restricted cash		(869	)		(78	)		(934	)		(188	)


Net cash used for investing activities		(143,349	)		(75,840	)		(696,528	)		(252,984	)


Cash flow from financing activities:
Bank repayments		(10,000	)		—			(140,000	)		(19,800	)
Bank borrowings		10,000			10,000			210,000			39,800
Payments on capital lease obligations — Genesis		(145	)		(132	)		(425	)		(386	)
Income tax benefit from equity awards		5,041			—			15,193			—
Issuance of common stock		4,952			3,314			137,263			11,139
Purchase of treasury stock		(3,423	)		(1,955	)		(5,545	)		(5,119	)
Costs of debt financing		(329	)		—			(417	)		—


Net cash provided by financing activities		6,096			11,227			216,069			25,634


Net increase (decrease) in cash and cash equivalents		(1,888	)		11,674			(136,165	)		3,951

Cash and cash equivalents at beginning of period		30,812			25,316			165,089			33,039


Cash and cash equivalents at end of period	$	28,924		$	36,990		$	28,924		$	36,990


Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	1,519		$	374		$	17,416		$	9,280
Cash paid during the period for income taxes		4			1,500			4,210			9,000
Interest capitalized		3,731			415			6,740			1,049

(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 September 30, 2006 and the consolidated results of its operations and cash flows for the three and nine month periods ended September 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”), non-vested restricted stock and any other convertible securities outstanding. For the three and nine month periods ended September 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, Stockholders’ 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 nine month periods ended September 30, 2006 and 2005.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Share amounts in Thousands	2006		2005		2006		2005
Weighted average common shares — basic		117,917		112,159		115,864		111,466

Potentially dilutive securities:
Stock options and SARs		5,183		6,264		6,172		6,691
Restricted stock		866		1,064		1,019		941

Weighted average common shares — diluted		123,966		119,487		123,055		119,098

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The weighted average common shares – basic amount excludes 1,422,229 shares at September 30, 2006 and 2,018,000 shares at September 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 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 September 30, 2006 and 2005, stock options and SARs to purchase approximately 111,000 and 131,000 shares of common stock, and for the nine months ended September 30, 2006 and 2005, stock options and SARs to purchase approximately 117,000 and 304,000 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 compensation plans.

Recent Accounting Pronouncements

In July 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We are currently evaluating the impact this interpretation will have on our consolidated financial statements. This interpretation will be effective for Denbury beginning January 1, 2007.

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 Free State pipeline (pipeline from Jackson 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.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 then 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. Our goal is to have this CO₂ line installed within the next two years, with initial oil production from tertiary operations currently anticipated during 2010. Currently, there is neither significant oil production nor proved oil reserves at Delhi. The purchase price of approximately $50 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 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 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 nine months ended September 30, 2006 and 2005.

3. STOCKHOLDERS’ EQUITY

On April 25, 2006, we closed on the $125 million sale (net to Denbury) of 3,492,595 shares of common stock 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.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the changes in our asset retirement obligations for the nine months ended September 30, 2006.


	Nine Months Ended
	September 30, 2006
Amounts in thousands
Beginning asset retirement obligation, as of 12/31/2005	$	27,088
Liabilities incurred and assumed during period		9,412
Revisions in estimated cash flows		1,519
Liabilities settled during period		(965	)
Accretion expense		1,863

Ending asset retirement obligation as of 9/30/2006	$	38,917

At September 30, 2006, $3.8 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 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 $7.6 million at September 30, 2006 and $6.7 million at December 31, 2005 and are included in “Other assets” in our Condensed Consolidated Balance Sheets.

5. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS


	September 30,			December 31,
Amounts 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		(1,263	)		(1,409	)
Senior bank loan		70,000			—
Capital lease obligations — Genesis		6,018			6,444
Other		205			—

Total		449,960			380,035
Less current obligations		616			574

Long-term debt and capital lease obligations	$	449,344		$	379,461

On September 14, 2006, we entered into a Sixth Amended and Restated Credit Agreement with our nine banks which modified our previous bank credit agreement. The new agreement (i) improves the credit pricing under the agreement, (ii) extends the term of the credit arrangements by two and one-half years to September 14, 2011, (iii) increases the borrowing base from $300 million to $500 million, (iv) increases the maximum facility size from $300 million to $800 million, and (v) makes other minor modifications and corrections. Under the new agreement, the commitment amount remained at $150 million. The borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request we make in excess of the commitment amount ($150 million), up to the borrowing base limit, although the banks are not obligated to fund any amount in excess of the commitment amount. The new credit agreement maintains the structure of semi-annual reviews of the borrowing base and commitment amount.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. STOCK COMPENSATION PLANS

Incentive Programs

Denbury has two stock compensation 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 stockholders 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 September 30, 2006, a total of 1,042,513 shares were available for future issuance of awards, of which only 326,281 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 stock 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 completely replaced the use of stock options for employees with SARs settled in stock, as SARs are less dilutive to our stockholders while providing an employee with essentially the same economic benefits as stock options. The stock options and SARs generally become exercisable over a four-year vesting period with the specific terms of vesting determined at the time of grant based on guidelines established by the Board of Directors. The stock options and SARs 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 stock options and SARs 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 directors’ 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.

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 Nine Months Ended September 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.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the third quarter of 2006, our Vice President of Marketing announced his retirement and departed the Company on August 31, 2006, in connection with which we expensed approximately $750,000 related to options and restricted stock that he held.

Total compensation expense charged against income for stock-based compensation was $3.4 million and $14.7 million (including the $5.3 million resulting from modification of Mr. Worthey’s equity awards discussed above) for the three and nine months ended September 30, 2006, respectively. Part of this expense, $0.3 million and $1.1 million for the three and nine months ended September 30, 2006, respectively, was included in “Lease operating expenses” for stock compensation expense associated with our field employees, and the remaining $3.1 million and $13.6 million for the three and nine months ended September 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 $0.9 million and $3.9 million for the three and nine months ended September 30, 2006, respectively. Share-based compensation capitalized as part of “Oil and Natural Gas Properties” was $0.4 million and $1.3 million for the three and nine months ended September 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		Nine Months
	Ended		Ended
	September 30,		September 30,
Amounts in thousands, except per share amounts	2005		2005
Net income, as reported	$	38,546	$	109,285
Add: stock-based compensation included in reported net income, net of related tax effects		679		2,073
Less: stock-based compensation expense applying fair value based method, net of related tax effects		2,152		5,627

Pro-forma net income	$	37,073	$	$105,731


Net income per common share
As reported:
Basic	$	0.34	$	0.98
Diluted		0.32		0.92
Pro forma:
Basic	$	0.33	$	0.95
Diluted		0.31		0.90

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 the Condensed Consolidated Balance Sheet. The effect of applying SFAS No. 123(R) during the three and nine months ended September 30, 2006 was to decrease

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

net income by approximately $1.5 million and $5.0 million, respectively, for stock compensation expense that would only have been presented in footnote disclosures under the old requirements of SFAS No. 123. The effect on earnings per share for the three months ended September 30, 2006 was a decrease of $0.01 per both basic and diluted share, and for the nine months ended September 30, 2006 was a decrease of $0.04 per both basic and diluted share. Additionally, cash flow from operations was lower and cash flow from financing activities was higher by approximately $5.0 million and $15.2 million for the three and nine months ended September 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.

Stock Options and SARs

The fair value of each stock option or SAR 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 stock options and SARs 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.


	Nine months ended			Year ended
	September 30, 2006			December 31, 2005
Weighted average fair value of options granted		$12.69		$	6.94
Risk free interest rate		4.52	%		3.80	%
Expected life		4.9 to 6.9 years		5 years
Expected volatility		41.3	%		42.6	%
Dividend yield		—			—

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


	Nine Months Ended					Year Ended
	September 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		498,306			27.10		2,483,254			16.29
Exercised		(1,773,795	)		5.45		(1,797,146	)		5.37
Forfeited		(424,009	)		10.45		(160,350	)		8.86

Outstanding at end of period		7,706,574			9.78		9,406,072			8.07


Exercisable at end of period		2,528,672		$	4.90		2,509,635		$	4.50

The total intrinsic value of stock options and SARs exercised during the nine months ended September 30, 2006 and the year ended December 31, 2005 was approximately $43.8 million and $24.8 million, respectively. The aggregate intrinsic value of stock options and SARs outstanding at September 30, 2006 was approximately $147.4 million and these options and SARs have a weighted-average remaining contractual life of 6.4 years. The aggregate intrinsic value of options exercisable at September 30, 2006 was approximately $60.7 million and these stock options and SARs have a weighted-average remaining contractual life of 3.9 years.

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A summary of the status of our non-vested stock options and SARs as of September 30, 2006, and the changes during the nine months ended September 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		498,306			12.69
Vested		(1,792,832	)		2.97
Forfeited		(424,009	)		4.81

Non-vested at September 30, 2006		5,177,902			5.46

As of September 30, 2006, there was $13.3 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 stock option exercises under share-based payment arrangements for the nine months ended September 30, 2006 and year ended December 31, 2005 was $9.7 million in each period. The tax benefit realized from stock option and SAR exercises of share-based payment arrangements totaled $13.6 million for the nine months ended September 30, 2006 and $8.6 million for the year ended December 31, 2005.

Restricted Stock

As of September 30, 2006 we had issued 2,423,719 shares of restricted stock pursuant to the 2004 Plan and have recorded deferred compensation expense of $26.7 million, the fair market value of the shares on the grant dates. This expense is amortized over the applicable five-year, four-year, or retirement date vesting periods. As of September 30, 2006, there was $14.3 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 years.

A summary of the status of our non-vested restricted stock grants as of September 30, 2006, and the changes during the nine months ended September 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		103,719			29.39
Vested		(524,815	)		10.17
Forfeited		(170,675	)		10.26

Non-vested at September 30, 2006		1,422,229			11.53

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 account 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 (loss) for the three months ended September 30, 2006 and 2005 was $157,000 and ($55,000), respectively, and for the nine months ended September 30, 2006 and

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2005 was $716,000 and $276,000, respectively. Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed the bank debt of Genesis, which as of September 30, 2006 was $6.0 million, plus $9.2 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.

During the second and third quarters of 2006, we invested a total of $2.1 million in a Louisiana petroleum coke-to-ammonia project that is in the development stage and we have committed to invest an additional $0.9 million. All of our investment 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 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 nine months of 2006 and 2005, we expensed $3.3 million and $3.0 million, respectively, for these transportation services. Denbury received other miscellaneous payments from Genesis for the nine months ended September 30, 2006 and 2005, including $90,000 in each period of director fees for certain executive officers of Denbury that are board members of Genesis, and $670,000 and $387,000, 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 our crude oil from certain of our fields in Southwest Mississippi, and to transport CO₂ from our main CO₂pipeline to Brookhaven Field for our tertiary operations. We have accounted for these agreements as capital leases. The pipelines held under these capital leases are classified as property and equipment and are amortized using the straight-line method over the lease terms. Lease amortization is included in depreciation expense. The related obligations are recorded as debt. At September 30, 2006, we had $6.0 million of capital lease obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $616,000 was current. At December 31, 2005, we had $6.4 million of capital lease obligations with Genesis 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 September 30, 2006 and December 31, 2005, $33.9 million and $37.1 million, respectively, was recorded as deferred revenue of which $4.1 million was included in current liabilities at September 30, 2006 and December 31, 2005. We recognized deferred revenue of $1.2 million and $0.7 million during the three months ended September 30, 2006 and 2005 and $3.2 million and $2.0 million for the nine months ended September 30, 2006 and 2005, respectively, for deliveries under these volumetric production payments. We provide Genesis with certain processing and transportation services in connection with transporting CO₂ to their industrial customers for a fee of approximately $0.17 per Mcf of CO₂, which resulted in our receiving $1.3 million and $0.8 million in revenue for the three months ended September 30, 2006 and 2005 and $3.5 million and $2.3 million for the nine months ended September 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 September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
Revenues	$	229,551	$	300,577		$	726,496	$	814,321
Cost of sales		221,206		295,959			702,671		799,832
Other expenses		6,650		5,259			16,095		11,890
Income from discontinued operations		—		45			—		318

Net income (loss)	$	1,695	$	(596	)	$	7,730	$	2,917


	September 30,		December 31,
	2006		2005
Current assets	$	102,293	$	90,449
Non-current assets		90,689		91,328

Total assets	$	192,982	$	181,777


Current liabilities	$	97,627	$	92,611
Non-current liabilities		7,009		955
Partners’ capital		88,346		88,211

Total liabilities and partners’ capital	$	192,982	$	181,777

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Effective January 1, 2005, we elected to discontinue hedge accounting treatment for financial statement purposes for our oil and natural gas derivative contracts and accordingly de-designated our derivative instruments from hedge accounting treatment in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” 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 resulting 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 September 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					Nine Months
	Ended September 30,					Ended September 30,
Amounts in thousands	2006			2005		2006		2005
Settlements of derivative contracts — Oil	$	2,207		$	—	$	5,187	$	—
Settlements of derivative contracts — Gas		—			3,765		—		6,640
Reclassification of accumulated other comprehensive income balance		—			1,875		—		5,451
Fair value adjustments to derivative contracts		(14,582	)		6,178		5,597		6,523

Commodity derivative expense (income)	$	(12,375	)	$	11,818	$	10,784	$	18,614

Derivative Oil Contracts at September 30, 2006


					Fair Value at
	NYMEX Contract Prices Per Bbl				September 30, 2006
Type of Contract and Period	Bbls/d		Swap Price		(In Thousands)
Swap Contracts
Oct. 2006 - Dec. 2006		2,200	$	59.65	$	(944	)
Jan. 2007 - Dec. 2007		2,000		58.93		(6,376	)
Jan. 2008 - Dec. 2008		2,000		57.34		(7,660	)

At September 30, 2006, our derivative contracts were recorded at their fair value, which was a liability of $15.0 million.

9. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors of our subordinated debt. 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


	September 30, 2006
	Denbury		Denbury
	Resources Inc.		Onshore, LLC							Denbury
	(Parent and Co-		(Issuer and Co-		Guarantor					Resources Inc.
Amounts in thousands	Obligor)		Obligor)		Subsidiaries		Eliminations			Consolidated
Assets
Current assets	$	380,712	$	135,417	$	3,834	$	(378,026	)	$	141,937
Property and equipment		—		1,793,150		32		—			1,793,182
Investment in subsidiaries (equity method)		654,456		—		653,985		(1,297,607	)		10,834
Other assets		158,812		13,873		154		(157,148	)		15,691

Total assets	$	1,193,980	$	1,942,440	$	658,005	$	(1,832,781	)	$	1,961,644


Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	549,979	$	3,185	$	(378,026	)	$	175,138
Long-term liabilities		150,000		749,310		364		(157,148	)		742,526
Stockholders’ equity		1,043,980		643,151		654,456		(1,297,607	)		1,043,980

Total liabilities and stockholders’ equity	$	1,193,980	$	1,942,440	$	658,005	$	(1,832,781	)	$	1,961,644


	December 31, 2005
	Denbury		Denbury
	Resources Inc.		Onshore, LLC							Denbury
	(Parent and Co-		(Issuer and Co-		Guarantor					Resources Inc.
Amounts in thousands	Obligor)		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 September 30, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and Co-			(Issuer and		Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	2,812		$	189,226	$	6		$	—		$	192,044
Expenses		2,917			93,751		569			—			97,237

Income (loss) before the following:		(105	)		95,475		(563	)		—			94,807
Equity in net earnings of subsidiaries		59,393			—		60,004			(119,240	)		157

Income before income taxes		59,288			95,475		59,441			(119,240	)		94,964
Income tax provision (benefit)		(6	)		35,628		48			—			35,670

Net income	$	59,294		$	59,847	$	59,393		$	(119,240	)	$	59,294


	Three Months Ended September 30, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and Co-			(Issuer and		Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Co-Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	141,858	$	—		$	—		$	141,858
Expenses		41			82,825		383			—			83,249

Income (loss) before the following:		(41	)		59,033		(383	)		—			58,609
Equity in net earnings of subsidiaries		38,571			—		38,724			(77,350	)		(55	)

Income before income taxes		38,530			59,033		38,341			(77,350	)		58,554
Income tax provision (benefit)		(16	)		20,254		(230	)		—			20,008

Net income	$	38,546		$	38,779	$	38,571		$	(77,350	)	$	38,546

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Operations (continued)


	Nine Months Ended September 30, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and Co-			(Issuer and Co-		Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	8,406		$	555,785	$	6		$	—		$	564,197
Expenses		8,678			314,606		1,329			—			324,613

Income (loss) before the following:		(272	)		241,179		(1,323	)		—			239,584
Equity in net earnings of subsidiaries		147,594			—		149,156			(296,034	)		716

Income before income taxes		147,322			241,179		147,833			(296,034	)		240,300
Income tax provision (benefit)		(12	)		92,739		239			—			92,966

Net income	$	147,334		$	148,440	$	147,594		$	(296,034	)	$	147,334


	Nine Months Ended September 30, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and Co-			(Issuer and Co-		Guarantor						Resources Inc.
Amounts in thousands	Obligor)			Obligor)		Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	383,203	$	—		$	—		$	383,203
Expenses		123			219,509		862			—			220,494

Income (loss) before the following:		(123	)		163,694		(862	)		—			162,709
Equity in net earnings of subsidiaries		109,360			—		109,934			(219,018	)		276

Income before income taxes		109,237			163,694		109,072			(219,018	)		162,985
Income tax provision (benefit)		(48	)		54,036		(288	)		—			53,700

Net income	$	109,285		$	109,658	$	109,360		$	(219,018	)	$	109,285

DENBURY RESOURCES INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Cash Flows


	Nine Months Ended September 30, 2006
	Denbury			Denbury
	Resources Inc.			Onshore, LLC							Denbury
	(Parent and Co-			(Issuer and Co-			Guarantor				Resources Inc.
Amounts in thousands	Obligor)			Obligor)			Subsidiaries		Eliminations		Consolidated
Cash flow from operations	$	(146,911	)	$	490,504		$	701	$	—	$	344,294
Cash flow from investing activities		—			(696,528	)		—		—		(696,528	)
Cash flow from financing activities		146,911			69,158			—		—		216,069

Net increase (decrease) in cash		—			(136,866	)		701		—		(136,165	)
Cash, beginning of period		1			164,408			680		—		165,089

Cash, end of period	$	1		$	27,542		$	1,381	$	—	$	28,924


	Nine Months Ended September 30, 2005
	Denbury			Denbury
	Resources Inc.			Onshore, LLC								Denbury
	(Parent and Co-			(Issuer and Co-			Guarantor					Resources Inc.
Amounts in thousands	Obligor)			Obligor)			Subsidiaries			Eliminations		Consolidated
Cash flow from operations	$	(6,020	)	$	236,921		$	400		$	—	$	231,301
Cash flow from investing activities		—			(252,963	)		(21	)		—		(252,984	)
Cash flow from financing activities		6,020			19,614			—			—		25,634

Net increase in cash		—			3,572			379			—		3,951
Cash, beginning of period		1			32,881			157			—		33,039

Cash, end of period	$	1		$	36,453		$	536		$	—	$	36,990

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, 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. The combination of high commodity prices and record quarterly production resulted in another quarter of near record earnings and cash flow from operations. Production for the third quarter of 2006 was 37,561 BOE/d, 37% higher than production in the third quarter of 2005, with production increases in every operating area. Last year’s third quarter production was negatively affected by Hurricanes Katrina and Rita, with approximately 3,800 BOE/d of production estimated as having been deferred during that period. If last year’s third quarter production is adjusted to include the estimated deferred portion, the production increase between the comparative quarters would be reduced to approximately 21%. Commodity prices remained strong during the third quarter of 2006, although on a comparative BOE basis, prices for the two third quarters were approximately the same, oil being a little higher in the 2006 period and natural gas prices a little lower.

Other significant factors impacted the respective two quarters. During the third quarter of 2006, we recognized $14.6 million of income associated with non-cash mark-to-market fair value changes on our oil swaps as a result of the decline in oil prices late in the period. Conversely, during the third quarter of 2005, we recognized mark-to-market fair value and other non-cash expenses of $8.1 million associated with derivative contracts in place at that time as commodity prices increased during that period. We also capitalized approximately $3.7 million of interest expense in the third quarter of 2006, primarily related to the unevaluated properties included in our 2006 acquisitions, reducing our overall increase in interest expense to 11%, even though average debt levels were 81% higher in the third 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 third quarter of 2006. Operating expenses were also impacted by higher energy costs (electrical and fuel charges) and our continuing emphasis on tertiary operations. General and administrative expenses increased 18% between the comparative third quarters as a result of the continued growth in personnel and inflation in the industry, including a 5% pay raise to all employees effective July 1, 2006 in order to remain competitive with industry compensation levels. Lastly, our income tax expense increased primarily due to higher pre-tax income and the effective rate increased due to the loss of our ability to generate enhanced oil recovery credits during 2006 as a result of the high oil prices.

Net income for the first nine months of 2006 was $147.3 million as compared to $109.3 million of net income during the first nine months of 2005. The incremental net income during the first nine months of 2006 was attributable to most of the factors noted above, principally higher production, partially offset by higher costs. Higher commodity prices in 2006 also played a significant role in the nine month results, increasing oil and natural gas revenue.

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 schedule with regard to timing of planned activities. While it appears that the recent decline in commodity prices may be showing preliminary signs of slowing these trends, unless prices continue to decrease, we believe that 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 seven 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 areas. 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. We continue to acquire tertiary flood candidates to further expand our operations (see “2006 acquisitions” below). Please also 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 averaged of 10,114 BOE/d in the third quarter of 2006, a 14% increase over the third quarter of 2005 tertiary production level of 8,850 BOE/d, but approximately the same as our second quarter 2006 production level. Our CO₂ injections have been less than we originally forecasted due to a series of delays in obtaining equipment or completing facilities, resulting in a corresponding shortfall between our forecasted and actual tertiary oil production. We believe this temporary fluctuation in oil production does not indicate any issue with the proved and potential oil reserves recoverable with CO₂ because the historical correlation between oil production and CO₂ injections remains high.

2006 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 Free State pipeline (CO₂ pipeline from Jackson 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 equity offering at that time). During the third quarter of 2006, these fields produced an average of 2,339 BOE/d, up slightly from the 2,200 BOE/d at the time of acquisition. As of December 31, 2005, these fields had proved reserves of approximately 14.4 million BOEs. We operate all three fields and own the majority of the working interests.

April 2006 Equity Offering. On April 25, 2006, we closed the $125 million sale (net to Denbury) of 3,492,595 shares of common stock 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 capital budget for 2006, excluding acquisitions, is approximately $550 million, which at commodity futures prices as of the end of October 2006, is estimated to be at least $100 million more than our anticipated cash flow from operations, a shortfall which primarily results from the drop in commodity prices during the last few months. As of November 1, 2006, we had $84 million of bank debt outstanding, an amount that we estimate will increase another

DENBURY RESOURCES INC.

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

$10 million to $20 million during the fourth quarter to fund our capital program. We expect to end the year with around $100 million of bank debt. Further, we continue to pursue additional acquisitions of mature oil fields that have potential as 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 and commodity prices. Any additional acquisitions would be funded, at least temporarily, with bank or other debt. With the recent increase in our borrowing base (see “Revised bank credit agreement” below), we have more borrowing capacity than we currently plan or desire to use as our goal is to maintain our strong financial position.

We have not finalized our 2007 capital budget, but preliminarily expect it to be between $550 million and $650 million, excluding any potential acquisitions. This preliminary 2007 program includes an estimated $80 million to $90 million for a CO₂ pipeline from our CO₂ source at Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during 2006. It is our intent to refinance this pipeline, and one (or both) of our existing CO₂ pipelines, with Genesis Energy, L.P. by entering into some type of long-term financing or sale transaction, effectively paying for the cost of the pipeline over time and recouping cash previously spent. We have discussed with Genesis any such financing being conditioned upon Genesis achieving certain goals, primarily the acquisition of other economic projects that are not related to Denbury, based upon acquisition by Genesis of $1.50 of non-Denbury-related acquisitions for every $1.00 of financings or sales with Denbury. If Genesis is successful in acquiring properties from third parties and we reach mutually agreeable terms with Genesis to sell them certain Denbury properties, and if commodity prices do not decrease any further, we will likely spend at or near the upper end of our preliminary 2007 capital budget range. Otherwise, we will likely reduce our capital program to some degree to remain closer to our anticipated cash flow from operations.

Preliminarily, approximately 50% of our 2007 budget is expected to be spent on tertiary related operations, approximately 25% in the Barnett Shale area, and approximately 10% on exploration projects, with the balance spent on our properties in Mississippi or Louisiana. The 2007 budget will be set and approved by our Board of Directors at our next regularly scheduled board meeting in December 2006.

Revised bank credit agreement. On September 14, 2006, we entered into a Sixth Amended and Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative agent. The new agreement (i) improves the credit pricing under the agreement, (ii) extends the term of the credit arrangements by two and one-half years to September 14, 2011, (iii) increases the borrowing base from $300 million to $500 million, (iv) increases the maximum facility size from $300 million to $800 million, and (v) makes other minor modifications. Under the new agreement, the commitment amount remained at $150 million. The borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($150 million), up to the borrowing base limit, although the banks are not obligated to fund any amount in excess of the commitment amount. At September 30, 2006, we had outstanding $375.0 million (principal amount) of 7.5% subordinated notes, approximately $6.0 million of capital lease commitments, $70.0 million of bank debt, and a working capital deficit of approximately $33.2 million.

Sources and Uses of Capital Resources

During the first nine months of 2006, we spent $377.0 million on oil and natural gas exploration and development, $42.6 million on CO₂ exploration and development, and approximately $315.7 million on property acquisitions, for total capital expenditures of approximately $735.3 million. Our exploration and development expenditures included approximately $164.6 million spent on drilling, $22.7 million spent on geological, geophysical and acreage expenditures and $189.7 million incurred on facilities and recompletion costs. We funded these expenditures with $344.3 million of cash flow from operations, $125 million of equity, $70 million of bank borrowings, and a $13 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 $355.6 million for the first nine months of 2006, while cash flow from operations for the same period, the GAAP measure, was $344.3 million.

DENBURY RESOURCES INC.

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

Last year, during the first nine months of 2005 we spent $210.9 million on oil and natural gas exploration and development, $49.9 million on CO₂ exploration and development (including $27.9 million on our CO₂ pipeline being constructed to East Mississippi), and approximately $71.2 million on property acquisitions, for total capital expenditures of approximately $332.0 million. Our exploration and development expenditures included approximately $94.9 million spent for drilling, $20.1 million for geological, geophysical and acreage expenditures and $95.8 million for facilities and recompletion costs. Our 2005 first nine-month acquisition expenditures included the purchase of additional interest and acreage in the Barnett Shale area and purchase of two oil fields that may be potential tertiary flood candidates in the future, Cranfield and Lake St. John fields. We funded these expenditures with $231.3 million of cash flow from operations, $20.0 million of net bank borrowings, and a $19.9 million increase in our accrued capital expenditures, with the balance funded with cash remaining from our 2004 offshore property sale. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed under “Results of Operations — Operating Results” below) was $238.7 million for the first nine months of 2005, while cash flow from operations for the same period, the GAAP measure, was $231.3 million.

Off-Balance Sheet Arrangements

Commitments and Obligations

Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in the proved reserve reports. Further, one of our subsidiaries, the general partner of Genesis Energy, L.P., has guaranteed the bank debt of Genesis (which as of September 30, 2006, consisted of $6.0 million of debt and $9.2 million in letters of credit) and we have delivery obligations to deliver CO₂ to 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 by the end of the term.

During the third quarter of 2006, we committed to purchase a manufactured (anthropogenic) source of CO₂, the by-product of a planned petroleum coke gasification plant in Louisiana scheduled to commence operations in 2010. This plant, if completed, is expected to produce between 190 MMcf/d and 225 MMcf/d of CO₂ and our purchase price will vary depending on the oil price at that time and the level of compression provided by the seller. We currently estimate that our annual minimum purchase commitment will be $2.0 million over a 15 year period, but the actual purchase price could be several times that minimum amount. Our commitment is only binding if the plant is constructed, which is still uncertain as the plant is in a pre-construction phase.

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 as disclosed 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 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

DENBURY RESOURCES INC.

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

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 originally planned to drill three new CO₂ source wells during 2006. The first well drilled in early 2006 is currently awaiting connection to facilities, the construction of which has been delayed from the originally estimated completion date. Preliminary indications are that while this well 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. We have had various drilling problems with our second well and have sidetracked it twice, and as a result, the well is almost three months behind schedule and still drilling. This development well is not expected to add any significant incremental CO₂reserves, but should further increase our total productive capacity. As a result of the delays in the second well, which is nearing total depth, we recently contracted a second rig to spud the third well, which has commenced drilling but is not expected to reach total depth until the first quarter of 2007. 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 third quarter of 2006, our CO₂ production averaged 352 MMcf/d, as compared to 253 MMcf/d during the third quarter of 2005. We used 74% of the 2006 volumes, or 260 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 averaged 10,114 BOE/d in the third quarter of 2006, a 14% increase over our third quarter of 2005 tertiary production level of 8,850 BOE/d, but approximately the same as tertiary oil production in the second quarter of 2006. Our CO₂ injections have been less than we forecasted due to a series of different types of delays in obtaining equipment or completing facilities, resulting in a corresponding shortfall between our forecasted and actual tertiary oil production. This temporary fluctuation in oil production does not indicate any issue with the proved and potential oil reserves recoverable with CO₂ because the historical correlation between oil production and CO₂ injections remains high.


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

Brookhaven		—		—		—		125		547		798		965
Little Creek & Lazy Creek		3,709		3,847		3,357		3,210		3,006		3,056		2,623
Mallalieu (East and West)		4,235		4,582		4,565		5,562		5,219		5,385		5,243
McComb & Olive		700		988		928		1,011		932		1,062		1,242
Smithdale		—		—		—		31		54		74		41

Total tertiary oil production		8,644		9,417		8,850		9,939		9,758		10,375		10,114

We spent approximately $0.20 per Mcf to produce our CO₂during the third quarter of 2006, up from the 2005 third quarter average of $0.17 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 CO₂during the third quarter of 2006 was approximately $0.30, after inclusion of depreciation and amortization expense, up from the 2005 average of $0.25 per Mcf for these same reasons. On a nine month basis, we spent approximately $0.20 per Mcf to produce our CO₂during the first nine months of 2006, higher than our 2005 nine month average of $0.15 per Mcf, an increase consistent with the comparable quarterly trends. Our estimated total cost per thousand cubic feet of CO₂during the first nine months of 2006 was approximately $0.29, after inclusion of depreciation and amortization expense.

For the third quarter of 2006, our operating costs for our tertiary properties averaged $17.61 per BOE, up significantly from the $11.95 per BOE average in the third quarter of 2005 and from our 2005 annual average of $12.00 per BOE, but approximately the same as our second quarter of 2006 average of $17.42 per BOE. The higher costs were a result of higher CO₂ costs which represent approximately 30% of our total tertiary operating costs (see prior paragraph), higher fuel and energy costs (which represent almost 35% of our total tertiary operating costs), higher rental payments on leased equipment, and general cost inflation in the industry, partially offset by higher production levels. In addition, we

DENBURY RESOURCES INC.

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

incurred approximately $2.4 million, or approximately $2.59 per BOE during the third quarter of 2006, for operating expenses at three new tertiary floods where we commenced operations but have not yet seen any production response (initial response is expected late in 2006 or in early 2007).

Operating Results

As summarized in the “Overview” section above and discussed in more detail below, higher production levels, mark-to-market derivative income, partially offset by higher operating expenses, resulted in near-record quarterly earnings and cash flow from operations. Included in the first nine months of 2006 net income is the effect of approximately $5.8 million 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) and approximately $6.0 million of other non-cash stock charges associated with the departure of a senior vice president and retirement of another vice president, both during 2006.


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Amounts in thousands, except per share amounts	2006		2005			2006			2005
Net income	$	59,294	$	38,546		$	147,334		$	109,285
Net income per common share — basic		0.50		0.34			1.27			0.98
Net income per common share — diluted		0.48		0.32			1.20			0.92

Adjusted cash flow from operations (see below)	$	118,983	$	87,346		$	355,625		$	238,708
Net change in assets and liabilities relating to operations		16,382		(11,059	)		(11,331	)		(7,407	)

Cash flow from operations (1)	$	135,365	$	76,287		$	344,294		$	231,301


(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 period. 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 nine months of 2006, we used cash because of increases in trade and other receivables of approximately $12.7 million, while the other working capital changes generally offset each other. Conversely, during the first nine months of 2005, our accrued production receivables and trade accounts receivable increased as a result of higher revenue and increased spending, resulting in a $14.3 million use of cash; however, this was partially offset by increases in our accounts payable, accrued liabilities and production payable which resulted in additional cash resources of $7.5 million.

Certain of our operating results and statistics for the comparative third quarters and first nine months of 2006 and 2005 are included in the following table.

DENBURY RESOURCES INC.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Average daily production volumes
Bbls/d		23,468			18,369			23,018			19,745
Mcf/d		84,557			53,854			82,912			56,556
BOE/d ⁽¹⁾		37,561			27,345			36,837			29,171
Operating revenues (Thousands)
Oil sales	$	138,172		$	95,987		$	387,731		$	264,337
Natural gas sales		49,626			42,561			165,014			110,999

Total oil and natural gas sales	$	187,798		$	138,548		$	552,745		$	375,336


Oil and gas derivative contracts ⁽²⁾ (Thousands)
Cash expense on settlements of derivative contracts	$	(2,207	)	$	(3,765	)	$	(5,187	)	$	(6,640	)
Non-cash derivative (expense) income		14,582			(8,053	)		(5,597	)		(11,974	)

Total income (expense) from oil and gas derivative contracts	$	12,375		$	(11,818	)	$	(10,784	)	$	(18,614	)


Operating expenses (Thousands)
Lease operating expenses	$	42,225		$	25,983		$	120,148		$	75,702
Production taxes and marketing expenses		9,749			7,018			27,272			19,726

Total production expenses ⁽³⁾	$	51,974		$	33,001		$	147,420		$	95,428


CO₂ sales and transportation fees ⁽⁴⁾	$	2,687		$	2,594		$	7,049		$	5,841
CO₂ operating expenses		842			631			2,272			1,422

CO₂ operating margin	$	1,845		$	1,963		$	4,777		$	4,419


Unit prices — including impact of derivative settlements
Oil price per Bbl	$	62.97		$	56.80		$	60.88		$	49.04
Gas price per Mcf		6.38			7.83			7.29			6.76

Unit prices — excluding impact of derivative settlements
Oil price per Bbl	$	64.00		$	56.80		$	61.70		$	49.04
Gas price per Mcf		6.38			8.59			7.29			7.19

Oil and gas operating revenues and expenses per BOE ⁽¹⁾:
Oil and natural gas revenues	$	54.35		$	55.07		$	54.96		$	47.13


Oil and gas lease operating expenses	$	12.22		$	10.33		$	11.95		$	9.51
Oil and gas production taxes and marketing expense		2.82			2.79			2.71			2.48

Total oil and gas production expenses	$	15.04		$	13.12		$	14.66		$	11.99


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

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

(3)		Includes Transportation expense — Genesis.

(4)		Includes deferred revenue of $1.2 million and $0.7 million for the three months ended September 30, 2006 and 2005, respectively, and $3.2 million and $2.0 million for the nine months ended September 30, 2006 and 2005, respectively, associated with a volumetric production payment with Genesis. Includes transportation income from Genesis of $1.3 million and $0.8 million for the three months ended September 30, 2006 and 2005, respectively, and $3.5 million and $2.3 million for the nine months ended September 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, second, and third quarters of 2006 is listed in the following table.


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

Mississippi — non-CO₂ floods		13,057		12,788		10,998		11,475		12,455		12,633		13,069

Mississippi — CO₂ floods		8,644		9,417		8,850		9,939		9,758		10,375		10,114

Onshore Louisiana		6,710		5,791		5,169		6,992		8,349		8,623		8,221

Barnett Shale		1,313		2,052		2,150		3,048		3,953		4,621		4,952

Alabama		—		37		126		141		917		1,213		1,215

Other ⁽¹⁾		—		384		52		54		22		9		(10	)


Total Company		29,724		30,469		27,345		31,649		35,454		37,474		37,561


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

As outlined in the above table, production in the third quarter of 2006 increased 37% (10,216 BOE/d) over third quarter of 2005 levels, up slightly from second quarter 2006 levels, and up 26% during the comparable first nine month periods. The third quarter of 2005 was negatively affected by Hurricanes Katrina and Rita, as approximately 3,800 BOE/d of production is estimated as having been deferred during that period. If last year’s production is adjusted to include deferred production, the production increase between the comparative quarters would be reduced to approximately 21%, or approximately 6,400 BOE/d. Of this adjusted quarterly increase, the January 2006 acquisition contributed approximately 2,339 BOE/d of the increase (37%) in the 2006 third quarter average production (1,255 BOE/d to the Mississippi – non-CO₂ floods and 1,084 BOE/d to Alabama in the above table). These newly acquired properties contributed approximately 2,199 BOE/d to our average production in the second quarter of 2006, and approximately 2/3rds of that amount (two months production) during the first quarter of 2006. Our onshore Louisiana production for the first nine months of 2006 increased 2,512 BOE/d (43% increase) over the prior year’s first nine months level, due primarily to production increases at Thornwell and South Chauvin Fields as a result of 2005 and 2006 drilling activity in that area. The quarter-to-quarter fluctuations in Louisiana are a result of various wells coming on production, offset by depletion of others. Our Louisiana properties are generally shorter-lived properties than our properties in most other areas and therefore decline rather rapidly, requiring a consistent increase in new production in order to maintain production levels there.

Our production in the Barnett Shale area during the first nine months of 2006 increased 2,671 BOE/d (145% increase) over our first nine months of 2005 level, also as a result of increased drilling activity, with 40 to 50 wells planned in 2006. Production from this area has increased every quarter during the last two years, although this upward trend may not continue much longer as our activity level there is not expected to increase further.

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. Recent drilling activity in the Heidelberg Selma Chalk (natural gas) has increased production there slightly in recent quarters. See “CO₂ Operations” above for a discussion of the tertiary related production.

Our production for the third quarter of 2006 was weighted toward oil (62%), slightly less than the percentage of oil production (67%) during the third quarter of 2005, as a result of the recent increases in natural gas production in the Barnett Shale area and Louisiana.

DENBURY RESOURCES INC.

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

Oil and Natural Gas Revenues: Oil and natural gas revenues for the third quarter of 2006 increased $49.2 million, or 36%, from revenues in the comparable quarter of 2005, primarily as a result of higher production. When comparing the respective nine month periods, revenues increased $177.4 million, or 47%, as production also increased, assisted by higher commodity prices. Cash payments associated with our commodity derivative contracts of $2.2 million and $3.8 million for the third quarters of 2006 and 2005, respectively, were not significant to either period. See “Market Risk Management” for additional information regarding our hedging activities.

The 37% increase in production in the third quarter of 2006, as compared to production in the third quarter of 2005, increased oil and natural gas revenues by $51.8 million (105% of the total revenue increase), while slightly lower overall commodity prices in the 2006 quarterly period reduced revenue by $2.5 million, or 5% of the total revenue increase. On a nine month basis, the 26% increase in production in the first nine months of 2006, as compared to production in the first nine months of 2005, increased oil and natural gas revenues by $98.6 million (56% of the total revenue increase), and the increase in overall commodity prices in the 2006 nine month period increased revenue by $78.8 million, or 44% of the total revenue increase. Crude oil prices were higher in both 2006 periods than in the comparative 2005 periods, while natural gas prices were higher in 2006 for the comparative nine month periods, but lower during the third quarter of 2006 as compared to the third quarter of 2005. Our realized oil prices (excluding hedges) increased by 13% between the third quarters of 2005 and 2006 and by 26% between the comparable nine month periods, while our realized natural gas prices (excluding hedges) decreased by 26% between the third quarters of 2005 and 2006, but increased slightly by 1% between the comparable nine month periods. On a combined BOE basis, commodity prices were 1% lower in 2006 for the comparative third quarters and 17% higher for 2006 for the comparative first nine month periods.

The differentials between our net realized oil prices (excluding commodity derivative contracts) and NYMEX prices were slightly higher for the first nine months of 2006 as compared to the first nine months of 2005 and the comparative third quarter periods. Our average oil differential for the first nine months of 2006 was approximately $6.60 per Bbl as compared to $6.45 per Bbl during the first nine months of 2005 and an average of $6.17 per Bbl during the fourth quarter of 2005. On a quarterly basis, the average oil differential was $6.69 in the third quarter of 2006 as compared to $6.34 in the third quarter of 2005. The higher overall differential in 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 2006 as compared to 2005, primarily due to decreasing natural gas prices throughout most of the year. 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 nine months of 2006 was a positive variance of approximately $0.40 per Mcf, as compared to a negative variance of $0.48 per Mcf during the first nine months of 2005 and a negative variance of $1.03 per Mcf during the fourth quarter of 2005. On a quarterly basis, our average natural gas differential for the third quarter of 2006 was a positive variance of approximately $0.24 per Mcf, as compared to a negative variance of $0.97 per Mcf during the third quarter of 2005.

The changing commodity prices caused fluctuations in the mark-to-market value adjustments of our derivative contracts. We recognized a gain of $14.6 million in the third quarter of 2006 as a result of the decreasing prices, as compared to an expense of $8.1 million during the comparable period in 2005. For the nine month periods, we recognized an expense in both periods, $5.6 million during the 2006 nine month period as compared to $12.0 million in the 2005 nine month period.

Production Expenses: Our lease operating expenses increased between the comparable first nine months and third 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 $369,000 of non-cash charges to third quarter 2006 results with similar amounts in the first and second quarters of 2006, representing the stock compensation expense pertaining to operating personnel.

DENBURY RESOURCES INC.

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

During the third quarter of 2006, operating costs averaged $12.22 per BOE, up from $10.33 per BOE in the third quarter of 2005, and at approximately the same level as the $12.24 per BOE of operating costs incurred in the second quarter of 2006. Operating expenses incurred in connection with our tertiary operations increased from $9.7 million in the third quarter of 2005 to $16.4 million during the third quarter of 2006, as a result of the increased tertiary activity. 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 these increases 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 $5.7 million during the third quarter of 2006, and had a higher per BOE cost than our other properties due to repairs and clean-up performed on the properties. The trends were similar when comparing the respective first nine month periods.

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

General and Administrative Expenses

General and administrative (“G&A”) expenses increased 18% between the respective third quarters and 63% between the respective first nine months, as set forth below:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Net G&A expense (thousands)
Gross G&A expenses	$	23,322		$	17,737		$	70,794		$	46,862
State franchise taxes		662			447			1,355			1,065
Operator overhead charges		(11,510	)		(7,994	)		(31,471	)		(22,848	)
Capitalized exploration costs		(1,875	)		(1,238	)		(5,638	)		(3,640	)

Net G&A expense	$	10,599		$	8,952		$	35,040		$	21,439

Average G&A cost per BOE	$	3.07		$	3.56		$	3.48		$	2.69
Employees as of September 30		558			433			558			433

Gross G&A expenses increased $5.6 million, or 31%, between the respective third quarters and $23.9 million, or 51%, between the respective first nine months. The single biggest increase was due to the adoption of SFAS No. 123(R) in January 2006 which increased net G&A expense by approximately $6.6 million during the first nine months of 2006 ($1.7 million during the third 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, the third quarter of 2006 includes approximately $730,000 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). This quarterly non-cash compensation charge related to the 2004 grants is lower than the $1.0 million charged during the third quarter of 2005 as a result of the departure of two executives during 2006. In the second quarter of 2006, we incurred a $5.3 million charge to earnings 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. We also expensed approximately $750,000 in the third quarter of 2006 related to the retirement of our Vice President of Marketing.

G&A also increased along with higher compensation costs due to additional employees, associated expenses and wage increases. From September 30, 2005 to September 30, 2006, we had a net increase of 29% 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 in order to remain competitive with industry compensation levels. During the third quarter of 2005, we had one significant non-recurring item wherein we expensed $1.3 million for food,

DENBURY RESOURCES INC.

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

water, gasoline, power generators, and other essential supplies provided as part of relief efforts in Mississippi and Louisiana following the hurricanes that quarter.

The increase in gross G&A was offset in part by an increase in operator overhead recovery charges in the third quarter and first nine 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 third quarter and first nine months of 2006, the amount we recovered as operator overhead charges increased by 44% between the third quarters of 2005 and 2006 and increased by 38% between the first nine 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 51% between the third quarters of 2005 and 2006 and increased by 55% between the first nine 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 an 18% increase in net G&A expense between the respective third quarters and a 63% increase between the first nine months of 2006 and 2005. On a per BOE basis, G&A costs decreased 14% in the third quarter of 2006 as compared to the level of such costs in the third quarter of 2005, and increased 29% for the comparative first nine months of 2006 and 2005, both better results than the increase in gross costs as a result of the higher production levels.

Interest and Financing Expenses


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts in thousands, except per BOE amounts	2006			2005			2006			2005
Cash interest expense	$	8,456		$	4,658		$	24,902		$	13,694
Non-cash interest expense		284			264			852			673
Less: Capitalized interest		(3,731	)		(415	)		(6,740	)		(1,049	)

Interest expense	$	5,009		$	4,507		$	19,014		$	13,318

Interest and other income	$	1,559		$	716		$	4,403		$	2,026

Average net cash interest expense per BOE (1)	$	0.92		$	1.43		$	1.38		$	1.34
Average interest rate (2)		7.5	%		7.5	%		7.4	%		7.5	%
Average debt outstanding	$	452,638		$	249,711		$	447,813		$	242,711


(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 when comparing the third quarters and first nine months of 2005 and 2006, primarily due to substantially higher average debt levels offset in part by higher interest capitalized on our significant unevaluated properties, primarily related to the two recent acquisitions. 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 million as of September 30, 2006.

DENBURY RESOURCES INC.

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

Depletion, Depreciation and Amortization


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Amounts in thousands, except per BOE amounts	2006		2005		2006		2005
Depletion and depreciation of oil and natural gas properties	$	36,681	$	21,878	$	98,197	$	63,414
Depletion and depreciation of CO₂ assets		2,371		1,311		6,051		3,685
Asset retirement obligations		677		435		1,863		1,278
Depreciation of other fixed assets		1,459		716		3,972		1,896

Total DD&A	$	41,188	$	24,340	$	110,083	$	70,273

DD&A per BOE:
Oil and natural gas properties	$	10.81	$	8.87	$	9.95	$	8.12
CO₂ assets and other fixed assets		1.11		0.81		1.00		0.70

Total DD&A cost per BOE	$	11.92	$	9.68	$	10.95	$	8.82

Our depletion, depreciation and amortization (“DD&A”) rate on a per BOE basis increased 23% between the respective third quarters and increased 24% between the respective first nine months, primarily due to rising costs, although a minor reserve revision and lower commodity prices also contributed to the increase. As a result of cost inflation in the industry, we have adjusted the estimated future development costs on our undeveloped properties upward almost every quarter, the primary factor in rising DD&A rates per BOE. Our third quarter 2006 DD&A rate was also negatively impacted by a writedown of reserves on our Westervelt well, on the Gumbo prospect in Terrebonne Parish, as the production results during the first month of production indicate substantially lower reserves than the originally estimated two MMBOE. We are still optimistic about the potential of the prospect area and recently spudded a second well in this prospect area. Further, the decline in commodity prices during the third quarter resulted in our losing approximately 1.0 MMBOE of proved reserves at September 30, 2006 as compared to reserve quantities at June 30, 2006. representing the reduction of reserves due to a shorter economic life when commodity prices decrease.

We allocated approximately $124 million of our $250 million January 2006 acquisition and virtually all of the second quarter 2006 $50 million Delhi acquisition to unevaluated properties to reflect the significant potential 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 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 initiated CO₂injections at three East Mississippi fields in the first nine months of 2006, the magnitude and ability to book any potential incremental proved reserves at these fields before year-end 2006 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 nine months of 2006 as compared to the DD&A rate during the comparative first nine 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).

DENBURY RESOURCES INC.

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

Income Taxes


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts in thousands, except per BOE amounts and tax rates	2006			2005			2006			2005
Current income tax expense	$	5,419		$	7,684		$	12,856		$	17,320
Deferred income tax expense		30,251			12,324			80,110			36,380

Total income tax expense	$	35,670		$	20,008		$	92,966		$	53,700

Average income tax expense per BOE	$	10.32		$	7.95		$	9.24		$	6.74
Effective tax rate		37.6	%		34.2	%		38.7	%		32.9	%

Our income tax provision for the 2006 and 2005 periods was based on an estimated statutory tax rate of approximately 39%. For the first nine months of 2005, our net effective tax rate was 32.9%, lower than the statutory rate primarily due to the recognition of enhanced oil recovery credits (“EOR”) which lowered our overall tax expense. For 2006 we will not earn any additional EOR credits because of the high oil prices during 2005, which completely phased out our ability to earn any additional credits for 2006. As a result, our effective tax rate will more closely approximate our statutory tax rate in 2006. 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 2006. Our effective tax rates for the third quarter and nine months ended September 30, 2006 are slightly less than our estimated statutory rate due primarily to a revision to our previous estimate of EOR credits.

In both periods, the current income tax expense represents our anticipated alternative minimum cash taxes that we cannot offset with EOR credits. As of December 31, 2005, we had an estimated $44.7 million of EOR credit carryforwards that we can utilize to reduce a portion of our cash taxes. These EOR credits do not begin to expire until 2023.

DENBURY RESOURCES INC.

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

Per BOE Data

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Per BOE data	2006			2005			2006			2005
Oil and natural gas revenues	$	54.35		$	55.07		$	54.96		$	47.13
Loss on settlements of derivative contracts		(0.64	)		(1.50	)		(0.52	)		(0.83	)
Lease operating expenses		(12.22	)		(10.33	)		(11.95	)		(9.51	)
Production taxes and marketing expenses		(2.82	)		(2.79	)		(2.71	)		(2.48	)

Production netback		38.67			40.45			39.78			34.31
Non-tertiary CO₂ operating margin		0.53			0.78			0.48			0.55
General and administrative expenses		(3.07	)		(3.56	)		(3.48	)		(2.69	)
Net cash interest expense		(0.92	)		(1.43	)		(1.38	)		(1.34	)
Current income taxes and other		(0.78	)		(1.52	)		(0.04	)		(0.86	)
Changes in assets and liabilities relating to operations		4.74			(4.40	)		(1.12	)		(0.93	)

Cash flow from operations		39.17			30.32			34.24			29.04
DD&A		(11.92	)		(9.68	)		(10.95	)		(8.82	)
Deferred income taxes		(8.75	)		(4.90	)		(7.97	)		(4.57	)
Non-cash hedging adjustments		4.22			(3.20	)		(0.56	)		(1.50	)
Changes in assets and liabilities and other non-cash items		(5.56	)		2.78			(0.11	)		(0.43	)

Net income	$	17.16		$	15.32		$	14.65		$	13.72

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 September 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	2011		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 September 30, 2006 is 6.3%)

Fixed rate debt:
7.5% subordinated debt, net of discount, due 2013	$	—	$	225,000	$	—	$	223,737	$	233,438
(The interest rate on the subordinated debt is a fixed rate of 7.5%)

7.5% subordinated debt, due 2015	$	—	$	—	$	150,000	$	150,000	$	155,625
(The interest 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 September 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 swap 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 September 30, 2006, our derivative contracts were recorded at their fair value, which was a net liability of approximately $15.0 million, an increase of approximately $5.6 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 prices between December 31, 2005 and September 30, 2006.

Based on NYMEX crude oil futures prices at September 30, 2006, oil prices were 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 September 30, 2006, we would expect to make future cash payments of $15.9 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 $4.6 million, and if futures prices were to increase by 10% we would expect to pay $27.2 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.

Recent Accounting Pronouncements

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.

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.

DENBURY RESOURCES INC.

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 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 Mobil Corporations, et al. During the third quarter of 2006, we settled litigation that was disclosed in our 2005 Form 10-K styled J. Paulin Duhe, Inc. vs. Texaco, Inc. et al. These settlements did not have any material impact on our results of operations or cash flows for any of the periods presented. 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.


	Page
Part I. Financial Information

Item 1. Financial Statements

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

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

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

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

Notes to Unaudited Condensed Consolidated Financial Statements		7-21

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22 - 37

Item 3. Quantitative and Qualitative Disclosures about Market Risk		37

Item 4. Controls and Procedures		38

Part II. Other Information

Item 1. Legal Proceedings		38

Item 1A. Risk Factors		38

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

Item 3. Defaults Upon Senior Securities		39

Item 4. Submission of Matters to a Vote of Security Holders		39

Item 5. Other Information		39

Item 6. Exhibits		39

Signatures		40
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906


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.


	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

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