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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2007


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

Commission file number 1-12935

DENBURY RESOURCES INC.

(Exact name of Registrant as specified in its charter)


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

5100 Tennyson Parkway Suite 1200 Plano, TX		75024
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code:		(972) 673-2000

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o

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



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o

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

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


Class		Outstanding at July 31, 2007
Common Stock, $.001 par value		122,038,105

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares)


	June 30,			December 31,
	2007			2006
Assets
Current assets
Cash and cash equivalents	$	32,577		$	53,873
Accrued production receivable		94,387			72,279
Related party receivable — Genesis		81			119
Trade and other receivables, net of allowance of $339 and $315		36,150			24,260
Deferred tax asset		6,266			5,855
Derivative assets		8,830			26,883

Total current assets		178,291			183,269

Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved		2,546,558			2,226,942
Unevaluated		318,444			293,657
CO₂ properties and equipment		336,103			267,483
Other		45,656			43,133
Less accumulated depletion and depreciation		(1,037,012	)		(951,447	)

Net property and equipment		2,209,749			1,879,768

Investment in Genesis		10,106			10,640
Deposits on property under option or contract		49,056			49,002
Other assets		19,649			17,158

Total assets	$	2,466,851		$	2,139,837

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	120,318		$	139,111
Oil and gas production payable		61,454			52,244
Derivative liabilities		9,624			4,302
Deferred revenue — Genesis		4,070			4,070
Short-term capital lease obligations		702			671

Total current liabilities		196,168			200,398

Long-term liabilities
Capital lease obligations		6,035			6,387
Long-term debt, net of discount or premium		694,611			507,786
Asset retirement obligations		43,862			39,331
Derivative liabilities		5,220			6,834
Deferred revenue — Genesis		26,821			28,843
Deferred tax liability		270,043			235,780
Other		13,099			8,419

Total long-term liabilities		1,059,691			833,380

Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.001 par value, 250,000,000 shares authorized; 121,985,444 and 120,506,815 shares issued at June 30, 2007 and December 31, 2006, respectively		122			121
Paid-in capital in excess of par		640,158			616,046
Retained earnings		577,215			498,032
Accumulated other comprehensive income		57			—
Treasury stock, at cost, 298,218 and 370,327 shares at June 30, 2007 and December 31, 2006, respectively		(6,560	)		(8,140	)

Total stockholders’ equity		1,210,992			1,106,059

Total liabilities and stockholders’ equity	$	2,466,851		$	2,139,837

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007		2006
Revenues and other income
Oil, natural gas and related product sales:
Unrelated parties	$	217,479		$	189,369		$	386,602	$	363,463
Related party — Genesis		—			35			11		1,484
CO₂ sales and transportation fees		3,394			2,374			6,485		4,362
Interest income and other		1,764			1,469			3,547		2,844

Total revenues		222,637			193,247			396,645		372,153

Expenses
Lease operating expenses		57,207			41,751			107,764		77,923
Production taxes and marketing expenses		9,035			8,441			17,863		15,386
Transportation expense — Genesis		1,351			995			2,727		2,137
CO₂ operating expenses		1,204			785			1,907		1,430
General and administrative		11,694			14,574			23,128		24,441
Interest, net of amounts capitalized of $4,321, $2,735, $8,354, and $3,009, respectively		8,356			5,751			14,431		14,005
Depletion, depreciation, and amortization		46,235			36,152			87,262		68,895
Commodity derivative expense (income)		(15,049	)		11,529			11,858		23,159

Total expenses		120,033			119,978			266,940		227,376

Equity in net income (loss) of Genesis		(127	)		319			20		559


Income before income taxes		102,477			73,588			129,725		145,336

Income tax provision (benefit)
Current income taxes		7,343			(2,349	)		8,961		7,437
Deferred income taxes		32,567			31,675			41,581		49,859

Net income	$	62,567		$	44,262		$	79,183	$	88,040


Net income per common share — basic	$	0.52		$	0.38		$	0.66	$	0.77

Net income per common share — diluted	$	0.50		$	0.36		$	0.63	$	0.72

Weighted average common shares outstanding
Basic		119,793			116,471			119,395		114,820
Diluted		124,769			122,988			124,730		121,912

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Cash flow from operating activities:
Net income	$	62,567		$	44,262		$	79,183		$	88,040
Adjustments needed to reconcile to net cash flow provided by operations:
Depletion, depreciation and amortization		46,235			36,152			87,262			68,895
Non-cash derivative adjustments		(13,437	)		9,317			21,721			20,179
Deferred income taxes		32,567			31,675			41,581			49,859
Deferred revenue — Genesis		(1,066	)		(1,065	)		(2,022	)		(2,005	)
Stock based compensation		2,664			8,285			5,450			11,257
Amortization of debt issue costs and other		963			167			1,545			417
Changes in assets and liabilities related to operations:
Accrued production receivable		(23,550	)		(4,317	)		(22,070	)		(4,160	)
Trade and other receivables		(2,806	)		(10,198	)		(11,785	)		(5,940	)
Other assets		(124	)		7,500			(146	)		(2,632	)
Accounts payable and accrued liabilities		(10,515	)		(19,027	)		(15,501	)		(23,768	)
Oil and gas production payable		7,782			3,440			9,211			8,306
Other liabilities		972			226			1,168			481

Net cash provided by operating activites		102,252			106,417			195,597			208,929

Cash flow used for investing activities:
Oil and natural gas expenditures		(160,290	)		(131,502	)		(299,309	)		(250,101	)
Acquisitions of oil and gas properties		(7,523	)		(61,925	)		(46,660	)		(314,335	)
Change in accrual for capital expenditures		(4,514	)		4,584			(8,769	)		14,612
Acquisitions of CO₂ assets and CO₂ capital expenditures		(37,011	)		(17,143	)		(68,427	)		(28,167	)
Purchases of other assets		(1,870	)		(1,540	)		(4,487	)		(3,682	)
Dispositions of other assets		33			20			1,753			222
Proceeds from sales of oil and gas properties and equipment		5,835			2,038			5,840			2,038
Deposits on properties under option or contract		(21	)		—			(54	)		26,299
Increase in restricted cash		(43	)		(27	)		(906	)		(65	)

Net cash used for investing activities		(205,404	)		(205,495	)		(421,019	)		(553,179	)

Cash flow from financing activities:
Bank repayments		(140,000	)		(130,000	)		(140,000	)		(130,000	)
Bank borrowings		80,000			100,000			176,000			200,000
Payments on capital lease obligations		(166	)		(142	)		(327	)		(280	)
Issuance of subordinated debt		150,750			—			150,750			—
Issuance of common stock		5,477			127,846			10,687			132,311
Income tax benefit from equity awards		6,280			4,317			8,840			10,152
Purchase of treasury stock		(19	)		(2,115	)		(19	)		(2,122	)
Costs of debt financing		(1,600	)		—			(1,805	)		(88	)

Net cash provided by financing activities		100,722			99,906			204,126			209,973

Net increase (decrease) in cash and cash equivalents		(2,430	)		828			(21,296	)		(134,277	)
Cash and cash equivalents at beginning of period		35,007			29,984			53,873			165,089

Cash and cash equivalents at end of period	$	32,577		$	30,812		$	32,577		$	30,812

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	18,970		$	14,772		$	21,349		$	15,897
Cash paid during the period for income taxes		6,332			4,200			7,370			4,206
Interest capitalized		4,321			2,735			8,354			3,009

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Denbury” or “Company” refer to Denbury Resources Inc. and its subsidiaries. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2006. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of June 30, 2007 and the consolidated results of its operations and cash flows for the three and six month periods ended June 30, 2007 and 2006. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact on net income and common shares for the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and any other convertible securities outstanding. For the three and six month periods ended June 30, 2007 and 2006, there were no adjustments to net income for purposes of calculating diluted net income per common share. In April 2006, we issued 3,492,595 shares of common stock in a public offering. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three and six month periods ended June 30, 2007 and 2006.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Shares in Thousands)	2007		2006		2007		2006

Weighted average common shares — basic		119,793		116,471		119,395		114,820
Potentially dilutive securities:
Stock options and SARs		4,260		5,498		4,658		6,094
Restricted stock		716		1,019		677		998

Weighted average common shares — diluted		124,769		122,988		124,730		121,912

The weighted average common shares — basic amount excludes 1,531,141 shares at June 30, 2007 and 1,687,539 shares at June 30, 2006, of non-vested restricted stock that is subject to future vesting over time. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant). For purposes of calculating weighted average common shares — diluted, the non-vested restricted stock is included in the computation using the treasury stock method, with the proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. The dilution impact of these shares on our earnings per share calculation may increase in future periods, depending on the market price of our common stock during those periods.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

For the three months ended June 30, 2007 and 2006, common stock options to purchase approximately 80,000 and 60,000 shares of common stock, and for the six months ended June 30, 2007 and 2006, stock options to purchase approximately 157,000 and 66,000 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.

Recently Adopted Accounting Pronouncement

Uncertain Tax Positions

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

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

There was no cumulative adjustment made to the opening balance of retained earnings at January 1, 2007. Our uncertain tax positions relate primarily to timing differences and we do not believe any of such uncertain tax positions will materially impact our effective tax rate in future periods. The amount of unrecognized tax benefits did not materially change as of June 30, 2007. The amount of unrecognized tax benefits are expected to change over the next 12 months; however, such change is not expected to have a significant impact on our results of operations or financial position.

We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions. We are currently under examination by both the Internal Revenue Service and State authorities. The IRS is examining 2004 while Mississippi is auditing the periods from 1998 through 2003. We expect the 2004 IRS examination to be finalized in the third quarter of 2007 and we currently do not anticipate any material assessments as a result of this audit. Louisiana is auditing the periods from 2002 through 2004.

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

Recently Issued Accounting Pronouncement

Fair Value Option for Financial Assets and Liabilities

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Acquisitions

2007 Acquisition

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

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

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

2006 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. The adjusted purchase price was approximately $250 million (including the $25 million deposited as earnest money as of December 31, 2005), of which $124 million was assigned to unevaluated properties.

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. Approximately $49 million of the purchase price was assigned to unevaluated properties.

Note 3. Asset Retirement Obligations

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2007.


	Six Months Ended
Amounts in thousands	June 30, 2007

Balance, beginning of period	$	41,107
Liabilities incurred and assumed during period		3,099
Revisions in estimated retirement obligations		805
Liabilities settled during period		(996	)
Accretion expense		1,486

Balance, end of period	$	45,501

At June 30, 2007, $1.6 million of our asset retirement obligation was classified in “Accounts payable and accrued liabilities” under current liabilities in our Condensed Consolidated Balance Sheets. Liabilities incurred and assumed during the period are primarily for oil properties acquired during 2007. We hold cash and liquid investments in escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $8.5 million at June 30, 2007 and $7.6 million at December 31, 2006 and are included in “Other assets” in our Condensed Consolidated Balance Sheets.

Note 4. Notes Payable and Long-term Indebtedness


	June 30,			December 31,
Amounts in thousands	2007			2006

7.5% Senior Subordinated Notes due 2015	$	300,000		$	150,000
Premium on Senior Subordinated Notes due 2015		728			—
7.5% Senior Subordinated Notes due 2013		225,000			225,000
Discount on Senior Subordinated Notes due 2013		(1,117	)		(1,214	)
Senior bank loan		170,000			134,000
Capital lease obligations — Genesis		5,561			5,869
Capital lease obligations		1,176			1,189

Total		701,348			514,844
Less current obligations		702			671

Long-term debt and capital lease obligations	$	700,646		$	514,173

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

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

5. Related Party Transactions — Genesis

Interest in and Transactions with Genesis

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

We are accounting for our 9.25% ownership in Genesis’ under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore we do not consolidate Genesis. Our equity in Genesis’ net income (loss) for the three months ended June 30, 2007 and 2006 was ($0.1) million and $0.3 million, respectively, and for the six months ended June 30, 2007 and 2006 was $20,000 and $0.6 million, respectively. Denbury received pro-rata distributions from Genesis of $0.6 million and $0.4 million for the six months ended June 30, 2007 and 2006, respectively. We also received $0.1 million in each of these periods in directors’ fees for certain officers of Denbury that are board members of Genesis. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.

On July 25, 2007, Genesis closed on a previously announced acquisition wherein they acquired several energy related businesses from the Davison family of Ruston, Louisiana for total consideration of approximately $563 million, plus payment of approximately $35.1 million for certain purchase price adjustments and for estimated working capital of the sellers. These businesses include a trucking operation for petroleum products and other bulk commodities, terminal storage of refined petroleum products, a refinery service operation which processes sour gas streams at several refining operations, and a wholesale petroleum products marketing business. Approximately one-half of the acquisition was funded by debt from Genesis’ bank credit facility and approximately one-half through the issuance of Genesis common units to the seller. In conjunction with that acquisition, we exercised our right to maintain our pro rata (7.4%) ownership of common units, acquiring 1,074,882 additional common units for approximately $22.4 million, in addition to our capital contribution of an additional $6.2 million as general partner to maintain our 2% general partner’s capital interest.

Oil Sales and Transportation Services

We utilize Genesis’ trucking services and common carrier pipeline in Mississippi to transport certain of our crude oil production to sales points where it is sold to third party purchasers. In the first six months of 2007 and 2006, we expensed $2.7 million and $2.1 million, respectively, for these transportation services.

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 CO₂ pipeline to Brookhaven Field for our tertiary operations. We have accounted for these agreements as capital leases. The pipelines held under these capital leases are classified as property and equipment and are amortized using the straight-line method over the lease terms. Lease amortization is included in depreciation expense. The related obligations are recorded as debt. At June 30, 2007, we had $5.6 million of capital lease obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $0.7 million was current. At December 31, 2006, we had $5.9 million of capital lease obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheet, of which $0.6 million was current.

CO₂ Volumetric Production Payments

During 2003 through 2005, we sold 280.5 Bcf of CO₂ to Genesis under three separate volumetric production payment agreements. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and recognize such revenue as CO₂ is delivered under the volumetric production payments. At June 30, 2007 and December 31, 2006, $30.9 million and $32.9 million, respectively, was recorded as deferred revenue of which $4.1 million was included in current liabilities at June 30, 2007 and December 31, 2006. We recognized deferred revenue of $1.1 million during each of the three month periods ended June 30, 2007 and 2006 and $2.0 million during each of the six month periods ended June 30, 2007 and 2006, for deliveries under these volumetric production payments. We provide Genesis

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

with certain processing and transportation services in connection with these agreements for a fee of approximately $0.17 per Mcf of CO_2. For these services, we recognized revenues of $1.2 million for each of the three month periods ended June 30, 2007 and 2006 and $2.3 million and $2.2 million for the six months ended June 30, 2007 and 2006, respectively.

We had a net receivable from Genesis of $0.1 million at June 30, 2007 and December 31, 2006 in current assets and a long-term payable to Genesis of $0.5 million at June 30, 2007.

Note 6. Derivative Instruments and Hedging Activities

Oil and Gas Derivative Contracts

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

The following is a summary of “Commodity derivative income (expense)” included in our Condensed Consolidated Statements of Operations:


	Three Months						Six Months
Amounts in thousands	Ended June 30,						Ended June 30,
	2007			2006			2007			2006
Receipt (payment) on settlements of derivative contracts — Oil	$	(1,108	)	$	(2,212	)	$	(981	)	$	(2,980	)
Receipt (payment) of settlements of derivative contracts — Gas		2,827			—			10,951			—
Fair value adjustments to derivative contracts		13,330			(9,317	)		(21,828	)		(20,179	)

Commodity derivative income (expense)	$	15,049		$	(11,529	)	$	(11,858	)	$	(23,159	)

Oil and Natural Gas Commodity Derivative Contracts at June 30, 2007:

Crude Oil Contracts at June 30, 2007:


					Estimated
	NYMEX Contract Prices Per Bbl				Fair Value at
					June 30, 2007
Type of Contract and Period	Bbls/d		Swap Price		(In Thousands)
Swap Contracts
July 2007 - Dec. 2007		2,000	$	58.93	$	(4,454	)
Jan. 2008 - Dec. 2008		2,000		57.34		(10,390	)

Natural Gas Contracts at June 30, 2007:


					Estimated
	NYMEX Contract Prices Per MMBtu				Fair Value at
					June 30, 2007
Type of Contract and Period	MMBtu/d		Swap Price		(In Thousands)
Swap Contracts
July 2007 - Dec. 2007		20,000	$	7.99	$	2,424
July 2007 - Dec. 2007		40,000		7.96		4,629
July 2007 - Dec. 2007		15,000		7.95		1,709

At June 30, 2007, our oil and natural gas derivative contracts were recorded at their fair value, which was a net liability of $6.1 million.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Interest Rate Lock Derivative Contracts

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

At June 30, 2007, the interest rate lock contracts have a fair value asset of approximately $0.2 million that was recorded in our June 30, 2007 Condensed Consolidating Balance Sheet. We recorded $57,000 (net of taxes of $36,000) in accumulated other comprehensive income in our June 30, 2007 Condensed Consolidating Balance Sheet and the ineffectiveness totaling $0.1 million was recognized as income in our Condensed Consolidating Statement of Operations for the six months ended June 30, 2007.

Note 7. Condensed Consolidating Financial Information

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Balance Sheets


	June 30, 2007
					Other					Denbury
	Denbury		Denbury		Guarantor					Resources Inc.
	Resources Inc.		Onshore, LLC		Subsidiaries		Eliminations			Consolidated
Amounts in thousands
Assets
Current assets	$	413,507	$	173,743	$	7,356	$	(416,315	)	$	178,291
Property and equipment		—		2,209,731		18		—			2,209,749
Investment in subsidiaries (equity method)		789,046		—		789,113		(1,568,053	)		10,106
Other assets		309,167		65,476		154		(306,092	)		68,705

Total assets	$	1,511,720	$	2,448,950	$	796,641	$	(2,290,460	)	$	2,466,851

Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	605,117	$	7,366	$	(416,315	)	$	196,168
Long-term liabilities		300,728		1,064,826		229		(306,092	)		1,059,691
Stockholders’ equity		1,210,992		779,007		789,046		(1,568,053	)		1,210,992

Total liabilities and stockholders’ equity	$	1,511,720	$	2,448,950	$	796,641	$	(2,290,460	)	$	2,466,851



	December 31, 2006
					Other					Denbury
	Denbury		Denbury		Guarantor					Resources Inc.
	Resources Inc.		Onshore, LLC		Subsidiaries		Eliminations			Consolidated
Amounts in thousands
Assets
Current assets	$	392,372	$	180,476	$	3,662	$	(393,241	)	$	183,269
Property and equipment		—		1,879,742		26		—			1,879,768
Investment in subsidiaries (equity method)		709,611		—		709,020		(1,407,991	)		10,640
Other assets		154,076		64,391		154		(152,461	)		66,160

Total assets	$	1,256,059	$	2,124,609	$	712,862	$	(1,953,693	)	$	2,139,837

Liabilities and Stockholders’ Equity
Current liabilities	$	—	$	590,602	$	3,037	$	(393,241	)	$	200,398
Long-term liabilities		150,000		835,627		214		(152,461	)		833,380
Stockholders’ equity		1,106,059		698,380		709,611		(1,407,991	)		1,106,059

Total liabilities and stockholders’ equity	$	1,256,059	$	2,124,609	$	712,862	$	(1,953,693	)	$	2,139,837

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations


	Three Months Ended June 30, 2007
						Other						Denbury
	Denbury			Denbury		Guarantor						Resources Inc.
	Resources Inc.			Onshore, LLC		Subsidiaries			Eliminations			Consolidated
Amounts in thousands
Revenues	$	5,531		$	222,619	$	18		$	(5,531	)	$	222,637
Expenses		5,646			119,244		674			(5,531	)		120,033

Income (loss) before the following:		(115	)		103,375		(656	)		—			102,604
Equity in net earnings of subsidiaries		62,676			—		63,245			(126,048	)		(127	)

Income before income taxes		62,561			103,375		62,589			(126,048	)		102,477
Income tax provision (benefit)		(6	)		40,003		(87	)		—			39,910

Net income	$	62,567		$	63,372	$	62,676		$	(126,048	)	$	62,567


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

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

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

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations (continued)


	Six Months Ended June 30, 2007
						Other						Denbury
	Denbury			Denbury		Guarantor						Resources Inc.
	Resources Inc.			Onshore, LLC		Subsidiaries			Eliminations			Consolidated
Amounts in thousands
Revenues	$	8,344		$	396,611	$	34		$	(8,344	)	$	396,645
Expenses		8,550			265,446		1,288			(8,344	)		266,940

Income (loss) before the following:		(206	)		131,165		(1,254	)		—			129,705
Equity in net earnings of subsidiaries		79,379			—		80,590			(159,949	)		20

Income before income taxes		79,173			131,165		79,336			(159,949	)		129,725
Income tax provision (benefit)		(10	)		50,595		(43	)		—			50,542

Net income	$	79,183		$	80,570	$	79,379		$	(159,949	)	$	79,183


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

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

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

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Cash Flows


	Six Months Ended June 30, 2007
							Other					Denbury
	Denbury			Denbury			Guarantor					Resources Inc.
	Resources Inc.			Onshore, LLC			Subsidiaries		Eliminations			Consolidated
Amounts in thousands
Cash flow from operations	$	33		$	195,195		$	369	$	—		$	195,597
Cash flow from investing activities		(170,258	)		(421,019	)		—		170,258			(421,019	)
Cash flow from financing activities		170,258			204,126			—		(170,258	)		204,126

Net increase (decrease) in cash		33			(21,698	)		369		—			(21,296	)
Cash, beginning of period		1			52,225			1,647		—			53,873

Cash, end of period	$	34		$	30,527		$	2,016	$	—		$	32,577



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

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

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

DENBURY RESOURCES INC.

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

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

You should read the following in conjunction with our financial statements contained herein and our Form 10-K for the year ended December 31, 2006, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K.

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

Overview

Operating results. Our average production levels were 12% higher in the second quarter of 2007 than during the second quarter of 2006 and 10% higher in the first half of 2007 than during the first half of 2006, with significant increases in our tertiary oil and Barnett Shale production, partially offset by significant production declines in our Louisiana onshore properties. Our second quarter average production rate of 41,916 BOE/d was a Company quarterly record, and 9% higher than our first quarter 2007 average production rate. Higher natural gas prices further improved 2007 second quarter results as our average realized per BOE commodity price during that period was 3% higher than during the second quarter of 2006, resulting in 15% higher revenues in the 2007 second quarter period. Conversely, commodity prices on a per BOE basis were 4% lower in the first half of 2007, partially offsetting our higher first half production, resulting in a net 6% overall increase in revenues for the first six months of 2007.

Excluding any impact of our commodity derivative income and expenses discussed below, our aggregate expenses increased 25% during the second quarter of 2007 as compared to the second quarter of 2006 due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), (iii) the timing impact of the continued expansion of our tertiary operations in which we expense the cost of our CO₂ injections and other operating costs even though production response to the injections will lag behind (see “Results of Operations — CO₂ Operations” for a more thorough discussion), (iv) significantly higher average debt levels to finance our $42 million acquisition on March 31, 2007 (see “Recent Acquisition” below) and due to continued spending in excess of cash flow from operations (see “Capital Resources and Liquidity”), and (v) higher compensation expense resulting from additional employees and increased salaries which we consider necessary in order to remain competitive in the industry. General and administrative expenses decreased in the 2007 period because the general increase in compensation costs during 2007 was more than offset by a $5.3 million charge to earnings in the second quarter of 2006 related to the departure of our former Senior Vice President of Operations.

During the first half of 2007, aggregate expenses (excluding any commodity and derivative income and expenses) also increased 25% overall with similar variances in all categories except for interest expense. Our interest expense increased significantly less on a six month basis as compared to the second quarter variance because debt levels were lower in the first quarter of 2007 than during the second quarter, reducing the percentage increase in debt levels on a six month basis as compared to the second quarter percentage increase.

In addition to affecting our revenue, fluctuations in natural gas prices also affected the market value of our derivative contracts. Quarter-end closing prices of the near-month derivative natural gas price futures for the last three quarters help illustrate this. At December 31, 2006, the near-month natural gas price futures closed at $6.30, at March 31, 2007, it closed at $7.73, and on June 30, 2007, it closed at $6.77. Since we entered into derivative contracts covering 80% to 90% of our anticipated 2007 natural gas production in late 2006 at an average price of approximately $7.96 per Mcf, these fluctuating quarter-end natural gas price futures caused significant non-cash mark-to-market value adjustments. We recorded a $35.2 million non-cash pre-tax mark-to-market charge to earnings in the first quarter of 2007, which partially reversed itself in the second quarter of 2007 with a $13.3 million non-cash mark-to-market pre-tax gain, or a net charge of $21.8 million for the six month period, all primarily related to our 2007 natural gas swaps and the changes in quarter-end

DENBURY RESOURCES INC.

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

natural gas price futures. During the 2006 periods, we recorded a non-cash mark-to-market charge to earnings of $10.9 million in the first quarter and a $9.3 million charge in the second, or a total charge of $20.2 million during the first half of 2006, all related to our oil derivative contracts in place at that time. The difference in these mark-to-market value adjustments was most pronounced in the second quarter comparison as the 2007 period included a $13.3 million gain and the 2006 period included a $9.3 million expense, a net difference of $22.6 million on a pre-tax basis.

The net result was net income of $62.6 million during the second quarter of 2007 as compared to $44.3 million during the second quarter of 2006 as the higher production levels, higher commodity prices and non-cash mark-to-market value adjustments to income more than offset the other higher expenses. On a six month basis, net income was $79.2 million during the first half of 2007 as compared to $88.0 million during the first half of 2006 as the higher production in 2007 was more than offset by lower commodity prices and higher expenses than in the first half of 2006.

While overall costs were higher in the 2007 periods than in the comparable 2006 periods, during 2007 the rate of inflation in our industry appears to have moderated, and in some cases, we are beginning to see modest cost reductions. Likewise, although goods and services are still in tight supply, there have been signs of improvement in overall availability; but some supply issues persist, including long lead times for certain items, such as compressors used in our tertiary recycle facilities and construction services for pipelines. It is difficult to forecast price trends and supply and service availability, which if adverse, can significantly impact both operating costs and capital expenditures, as well as cause delays in achieving our anticipated production targets.

Overview of tertiary operations. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO₂ that we own drive the play. Please refer to the section entitled “CO₂ Operations” below and contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2006 Form 10-K for further information regarding these operations, their potential, and the ramifications of this focus.

Oil production from our tertiary operations increased to an average of 13,683 BOE/d in the second quarter of 2007, a 32% increase over the second quarter 2006 tertiary production level of 10,375 BOE/d and a 16% increase over the first quarter 2007 tertiary production level. Production from our Phase II operations in eastern Mississippi (Soso, Eucutta and Martinville Fields) contributed 2,229 BOE/d (approximately two-thirds) to the increase over the prior year’s second quarter production, with the balance of the increase coming from our Phase I fields, except Little Creek Field which is on a gradual decline.

Proposed sale of Louisiana assets. In late May 2007, we announced that we were evaluating strategic alternatives for our Louisiana assets, other than our Louisiana oil properties that have potential for tertiary recovery operations. We have engaged an advisor and in early August we plan to open a data room for a potential sale. Assuming that we achieve bids for these properties that are acceptable to us, closing would likely occur early in the fourth quarter. Production from the properties that are currently being considered for sale averaged approximately 28.8 MMcfe/d (85% natural gas) during the second quarter of 2007.

Recent Acquisition by Genesis Energy. On July 25, 2007, Genesis Energy, L.P. (“Genesis”), a master limited partnership of which Denbury is the general partner, closed on a previously announced acquisition in which they acquired several energy related businesses from the Davison family of Ruston, Louisiana for total consideration of approximately $563 million, plus payment of approximately $35.1 million for certain purchase price adjustments and for estimated working capital of the sellers. These businesses include a trucking operation for petroleum products and other bulk commodities, terminal storage of refined petroleum products, a refinery service operation which processes sour gas streams at several refining operations, and a wholesale petroleum products marketing business. Approximately one-half of the acquisition was funded by debt from Genesis’ bank credit facility and approximately one-half through the issuance of Genesis common units to the seller. In conjunction with that acquisition, we exercised our right to maintain our pro rata (7.4%) ownership of common units, acquiring 1,074,882 additional common units for approximately $22.4 million, in addition to our capital contribution of an additional $6.2 million as general partner to maintain our 2% general partner’s capital interest.

DENBURY RESOURCES INC.

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

We have previously discussed with Genesis that upon Genesis achieving certain goals, primarily the acquisition of other economic projects that are not related to Denbury, that we would undertake to “drop-down” certain Denbury assets to Genesis based upon acquisition by Genesis of $1.50 of non-Denbury-related acquisitions for every $1.00 of sales from Denbury. These “drop-down” transactions are currently thought most likely to consist of property sales combined with associated transportation or service arrangements or direct financing leases, or a combination of both. As a result of the recent Genesis acquisition, we anticipate that during 2007, we will enter into “drop-down” transactions with Genesis involving our existing CO₂ pipelines, with a total currently estimated value of between $200 million and $250 million. These “drop-down” transactions would be subject to, among other things, negotiation of specific terms, the approval of the board of directors of both entities, and the receipt of fairness opinions by both companies, and is expected to occur early in the fourth quarter of 2007. We would anticipate similar transactions with Genesis for the new CO₂ pipeline we are constructing from Jackson Dome to Tinsley and Delhi Fields once that pipeline is completed, forecasted at this time to be during 2008. If in future periods Genesis is able to complete additional acquisitions of sufficient size with acceptable economic returns, and subject to the same types of conditions, we would anticipate similar transactions with Genesis with our proposed 280 to 300 mile CO₂ pipeline from Southern Louisiana to Hastings Field, located near Houston, Texas, probably during 2010.

Recent Acquisition. On March 30, 2007, we completed an acquisition of six producing oil and natural gas fields, two of which are future potential CO₂ tertiary oil flood candidates, collectively called the Seabreeze Complex, located near Houston, Texas, at a cost of approximately $41.7 million. Tertiary operations are not expected to commence at these fields until 2010 or 2011, following anticipated completion of the 280 to 300 mile CO₂ pipeline from Louisiana to Hastings Field (also near Houston). The acquisition was funded with bank financing under our existing credit facility. At the time of acquisition, these fields were producing approximately 400 BOE/d net to the acquired interests, and had estimated proved conventional reserves of approximately 525 MBOE. We operate all of these fields and own the majority of the working interests.

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

Capital Resources and Liquidity

Our current 2007 capital exploration and development budget is $690 million, excluding any acquisitions. We expect to spend approximately 60% of our 2007 budget on tertiary related operations, approximately 20% in the Barnett Shale area, and less than 10% on exploration projects, with the balance spent on our conventional properties in Mississippi and Louisiana. This capital program includes an estimated $110 million (of an anticipated $150 million) for a CO₂ pipeline from our CO₂ source at Jackson Dome to Tinsley and Delhi Fields, two oil fields acquired during 2006. Based on oil and natural gas commodity futures prices as of the end of July 2007, our capital budget is $175 million to $225 million greater than our anticipated cash flow from operations, a much greater shortfall than we have had in recent years. We plan to fund most, if not all, of this entire shortfall through transactions with Genesis whereby we would “drop-down” our two existing significant CO₂ pipelines to them (see “Overview — Recent Acquisition by Genesis Energy”). Alternatively, if a sale of our Louisiana assets is consummated (see “Overview — Proposed sale of Louisiana assets”), depending on the net proceeds therefrom, which is difficult to forecast, those proceeds could also fund our anticipated cash shortfall. If neither transaction is completed, we would plan to fund the cash shortfall with bank debt and could potentially reduce our capital budget later in the year.

As of July 31, 2007, we had $200 million of bank debt outstanding on a $500 million borrowing base, leaving us significant incremental borrowing capacity, more than we currently plan or desire to use, particularly considering the potential for significant cash proceeds later this year from the above contemplated transactions.

We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, during the last few years as commodity prices have increased, we have increased our capital budget throughout the year. As a result of the recent cost inflation in our industry, many of our recent budget increases have related to escalating costs rather than additional projects. Even though there are signs that the rate of this

DENBURY RESOURCES INC.

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

inflationary trend is subsiding, if costs do rise or we spend more than our estimated or forecasted amounts, we will either have to increase our capital budget or consider the elimination of a portion of our planned projects.

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

Amendment to our bank credit facility. On March 31, 2007, we amended our Sixth Amended and Restated Credit Agreement with our nine banks, led by JPMorgan Chase Bank, N.A., as administrative agent. The amendment (i) increased the commitment amount that the banks are committed to fund from $250 million to $350 million, (ii) reconfirmed the borrowing base of $500 million, (iii) authorized the $150 million subordinated debt offering (see “Overview — April 2007 Debt Issuance”), and (iv) authorized us to enter into a sale-leaseback type transaction for our CO₂ pipelines, not to exceed $300 million, with Genesis, in the type of transaction contemplated and discussed above (see “Overview — Recent Acquisition by Genesis”). With regard to our bank credit facility, the borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($350 million), up to the borrowing base limit ($500 million), although the banks are not obligated to fund any amount in excess of the commitment amount. At July 31, 2007, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and $200 million of bank debt.

Sources and Uses of Capital Resources


	Six Months Ended
	June 30,
Amounts in thousands	2007		2006
Capital expenditures
Oil and gas exploration and development
Drilling	$	159,448	$	102,058
Geological, geophysical and acreage		10,558		17,008
Pipelines and facilities		56,259		64,296
Recompletions		64,988		64,004
Capitalized interest		8,056		2,735

Total oil and gas exploration and development expenditures		299,309		250,101
Oil and gas property acquisitions		46,660		314,335

Total oil and natural gas capital expenditures		345,969		564,436
CO₂ capital expenditures, including capitalized interest		68,427		28,167

Total	$	414,396	$	592,603

Our 2007 capital expenditures have been funded with $195.6 million of cash flow from operations, $150.0 million from our issuance of subordinated debt in April, $36.0 million of net bank borrowings, and the balance funded with working capital. Adjusted cash flow from operations (a non-GAAP measure defined as cash flow from operations before changes in assets and liabilities as discussed below under “Results of Operations — Operating Results”) was $234.7 million for the first six months of 2007, while cash flow from operations for the same period, the GAAP measure, was $195.6 million.

Our 2006 expenditures were funded with $208.9 million of cash flow from operations, $132.3 million of equity issued and $70 million of net bank borrowings, with the balance funded from cash and other sources, including funds remaining from our December 2005 issuance of $150 million of subordinated debt.

DENBURY RESOURCES INC.

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

Off-Balance Sheet Arrangements

Commitments and Obligations

Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in the proved reserve reports. Our derivative contracts are discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements. Neither the amounts nor the terms of these commitments or contingent obligations have changed significantly from the year-end 2006 amounts reflected in our Form 10-K filed on March 1, 2007, except for (i) a commitment to a new building lease expected to commence in mid-2008 representing future payments of approximately $20 million over 136 months and (ii) additional commitments discussed below to purchase anthropogenic (manufactured) CO₂ from proposed gasification plants, if they are built.

We currently have long-term commitments to purchase manufactured CO₂ from three proposed gasification plants, if these plants are built, two proposed by the developers of the Faustina Hydrogen Products LLC and another by Rentech Inc. If all three plants are built, these synthetic sources are currently anticipated to provide us with an aggregate of 750 MMcf/d to 850 MMcf/d of CO₂ by 2012. The base price of CO₂ per Mcf from these synthetic sources is currently expected to be 1.5 to 2.0 times higher than our most recent all-in cost of CO₂ from natural sources (Jackson Dome) using current oil prices and assuming comparable compression levels. These predicted synthetic CO₂ prices are expected to be competitive with the cost of our natural CO₂ after adjusting for our share of potential carbon emissions credits using estimated current prices of CO₂ carbon credit futures. If all three plants are built, the aggregate purchase obligation for this CO₂ would be around $150 million per year at current oil prices and assuming comparable compression levels, before any potential savings from our share of carbon emissions credits. All of the contracts have price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on any of these plants and their construction is contingent on the satisfactory resolution of various issues, including financing, although the initial Faustina plant is currently scheduled to begin construction in late 2007 or early 2008, with completion scheduled in late 2010.

Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Off-Balance Sheet Arrangements — Commitments and Obligations” contained in our 2006 Form 10-K for further information regarding our commitments and obligations.

Results of Operations

CO₂ Operations

Our focus on CO₂ operations is becoming an ever-increasing part of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO₂, and we have outlined certain of this potential in our annual report and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the section entitled “CO₂ Operations” contained in our 2006 Form 10-K for further information regarding these matters.

During the remainder of 2007 we plan to drill additional CO₂ source wells to further increase our production capacity and reserves. We estimate that we are currently capable of producing between 650 MMcf/d and 700 MMcf/d of CO₂. During the second quarter of 2007, our CO₂ production averaged 477 MMcf/d, as compared to an average of approximately 448 MMcf/d during the first quarter of 2007, and average production of 290 MMcf/d during the first half of 2006. We used 81% of this production, or 387 MMcf/d, in our tertiary operations during the second quarter of 2007, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.

Our oil production from tertiary operations increased to an average of 13,683 BOE/d in the second quarter of 2007, a 32% increase over the second quarter of 2006 tertiary production level of 10,375 BOE/d, and a 16% increase over the first quarter of 2007 tertiary production levels. The table below shows our tertiary oil production by field for the first and second quarters of 2007 and all four quarters of 2006. We saw continued improved response from our newer floods at Smithdale, Martinville, Eucutta and Soso Fields, most of which were initiated during 2006. In addition, we continue to

DENBURY RESOURCES INC.

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

see improved response at most of our other floods, except for Little Creek Field, which is a mature flood and is expected to continue to decline over the next several years.


	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Second
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2006		2006		2006		2006		2007		2007

Phase I:
Brookhaven		547		798		965		1,014		1,422		1,794
Little Creek & Lazy Creek		3,006		3,056		2,623		2,279		2,117		1,974
Mallalieu (East and West)		5,219		5,385		5,243		4,994		5,470		5,802
McComb & Olive		932		1,062		1,242		1,467		1,497		1,257
Smithdale		54		74		41		63		314		627
Phase II:
Martinville		—		—		—		24		320		521
Eucutta		—		—		—		187		614		1,338
Soso		—		—		—		—		25		370

Total tertiary oil production		9,758		10,375		10,114		10,028		11,779		13,683

We spent approximately $0.19 per Mcf to produce our CO₂ during the first half of 2007, about the same as the 2006 first six months average of $0.20 per Mcf. Our estimated total cost per thousand cubic feet of CO₂ during the first half of 2007 was approximately $0.27, after inclusion of depreciation and amortization expense, down slightly from the 2006 average of $0.29 per Mcf. On a quarterly basis, we spent approximately $0.21 per Mcf to produce our CO₂during the second quarter of 2007, the same rate as the 2006 second quarter average, and in the same range as the six month amounts. Our estimated total cost per thousand cubic feet of CO₂during the second quarter of 2007 was approximately $0.29, after inclusion of depreciation and amortization expense.

For the first half of 2007, our operating costs for our tertiary properties averaged $20.38 per BOE, higher than the prior year’s first half average of $16.26 per BOE, but slightly lower than our fourth quarter 2006 average of $20.58 per BOE. The higher costs are primarily due to general cost inflation in the industry and the new floods initiated last year, which resulted in higher CO₂ costs, higher fuel and energy costs and higher rental payments on leased equipment. Because we expense all lease operating costs, including injection costs, associated with starting a new flood, we expect the lease operating expense per BOE for tertiary operations to initially be high, until production increases significantly. For example, for the first half of 2007, operating costs per BOE for our Phase I properties, which are generally more developed than our Phase II properties, were $17.29 per BOE, as compared to tertiary operating costs of $40.54 per BOE for Phase II, an area which first responded in late 2006. In comparison, our operating costs for Mallalieu Field, currently our highest volume tertiary producer, was $10.79 per BOE during the same period. We expect our operating costs to average between $13 and $15 per BOE over the life of a tertiary flood, even though our recent average tertiary operating costs have been higher, as we continue to implement additional floods.

Operating Results

As summarized in the “Overview” section above and discussed in more detail below, for the second quarter of 2007, higher production, higher commodity prices, and favorable non-cash mark-to-market value adjustments to income more than offset higher expenses, resulting in near-record quarterly earnings and cash flow from operations. On a six month basis, higher production was more than offset by lower commodity prices and higher expenses than in the first half of 2006, resulting in a slight decrease in net income during the 2007 six month period.

DENBURY RESOURCES INC.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Amounts in thousands, except per share amounts	2007			2006			2007			2006
Net income	$	62,567		$	44,262		$	79,183		$	88,040
Net income per common share — basic		0.52			0.38			0.66			0.77
Net income per common share — diluted		0.50			0.36			0.63			0.72
Adjusted cash flow from operations (see below)	$	130,493		$	128,793		$	234,720		$	236,642
Net change in assets and liabilities relating to operations		(28,241	)		(22,376	)		(39,123	)		(27,713	)

Cash flow from operations (1)	$	102,252		$	106,417		$	195,597		$	208,929

(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, a non-GAAP measure, is the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe it is important to consider adjusted cash flow from operations separately, as we believe it can often be a better way to discuss changes in operating trends in our business caused by changes in production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during that year. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices or significant changes in drilling activity. Adjusted cash flow from operations is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows.

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 all the periods, we used cash to fund a net increase in our other working capital items. During 2007, this was primarily caused by an increase in trade and production receivables as a result of our increased production volumes and higher level of activity, coupled with a decrease in our payables. During the first half of 2006, this was primarily caused by a decrease in our payables, partially offset by an increase in our receivables.

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

DENBURY RESOURCES INC.

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2007		2006			2007			2006
Average daily production volumes
Bbls/d		26,172		23,362			25,119			22,790
Mcf/d		94,459		84,671			90,007			82,076
BOE/d (1)		41,916		37,474			40,120			36,469
Operating revenues (in thousands)
Oil sales	$	151,178	$	136,118		$	269,310		$	249,559
Natural gas sales		66,301		53,286			117,303			115,388

Total oil and natural gas sales	$	217,479	$	189,404		$	386,613		$	364,947

Oil and gas derivative contracts (2) (in thousands)
Cash receipt (payment) on settlement of derivative contracts	$	1,719	$	(2,212	)	$	9,970		$	(2,980	)
Non-cash fair value adjustment income (expense)		13,330		(9,317	)		(21,828	)		(20,179	)

Total income (expense) from oil and gas derivative contracts	$	15,049	$	(11,529	)	$	(11,858	)	$	(23,159	)

Operating expenses (in thousands)
Lease operating expenses	$	57,207	$	41,751		$	107,764		$	77,923
Production taxes and marketing expenses		10,386		9,436			20,590			17,523

Total production expenses (3)	$	67,593	$	51,187		$	128,354		$	95,446

Non-tertiary CO₂ operating margin (in thousands)
CO₂ sales and transportation fees (4)	$	3,394	$	2,374		$	6,485		$	4,362
CO₂ operating expenses		1,204		785			1,907			1,430

CO₂ operating margin	$	2,190	$	1,589		$	4,578		$	2,932

Unit prices — including impact of derivative settlements (2)
Oil price per Bbl	$	63.01	$	62.99		$	59.02		$	59.78
Gas price per Mcf		8.04		6.92			7.87			7.77
Unit prices — excluding impact of derivative settlements (2)
Oil price per Bbl	$	63.48	$	64.03		$	59.23		$	60.50
Gas price per Mcf		7.71		6.92			7.20			7.77
Oil and gas operating revenues and expenses per BOE (1)
Oil and natural gas revenues	$	57.02	$	55.54		$	53.24		$	55.29

Oil and gas lease operating expenses	$	15.00	$	12.24		$	14.84		$	11.80
Oil and gas production taxes and marketing expense		2.72		2.77			2.84			2.65

Total oil and gas production expenses	$	17.72	$	15.01		$	17.68		$	14.45

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

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

(3)		Includes “Transportation expense — Genesis”.

(4)		Includes deferred revenue of $1.1 million for the three month periods ended June 30, 2007 and 2006, and $2.0 million for each of the six month periods ended June 30, 2007 and 2006, associated with volumetric production payments with Genesis. Also includes transportation income from Genesis of $1.2 million for each of the three month periods ended June 30, 2007 and 2006, and $2.3 million and $2.2 million for the six months ended June 30, 2007 and 2006, 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 2006 and the first and second quarters of 2007 is listed in the following table.


	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Second
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Operating Area	2006		2006		2006		2006		2007		2007

Mississippi — non-CO₂ floods		12,455		12,633		13,069		12,808		12,738		12,525
Mississippi — CO₂ floods		9,758		10,375		10,114		10,028		11,779		13,683
Onshore Louisiana		8,349		8,623		8,221		6,572		5,591		5,391
Texas		3,953		4,621		4,952		5,925		6,989		9,048
Alabama and other		939		1,222		1,205		1,286		1,208		1,269

Total Company		35,454		37,474		37,561		36,619		38,305		41,916

As outlined in the above table, production in the second quarter of 2007 increased 12% (4,442 BOE/d) over second quarter of 2006 levels, 9% over the first quarter 2007 levels, and 10% in the first six months of 2007 compared to production in the first six months of 2006. These increases from the 2006 periods are primarily due to increased production from our tertiary operations and the Barnett Shale, offset in part by decreases in our onshore Louisiana wells. The increase in our tertiary operations is discussed above under “Results of Operations — CO₂ Operations”.

Production in the Mississippi — non-CO₂ floods area was approximately the same as the prior year’s second quarter and down only slightly from the first quarter of 2007 level, as our continued drilling activity developing the Selma Chalk natural gas reservoir in the Heidelberg area has helped offset the gradual declines in oil production.

Our second quarter 2007 Barnett Shale production increased approximately 81%, to 8,368 BOE/d, from the prior year quarter’s level due to our successful drilling activity over the last year. During 2006, we drilled 46 horizontal wells and we drilled and completed 19 wells in the first half of 2007. We had four rigs working in the area during most of the first quarter of 2007, but have recently reduced our rig count in this area to three, which we plan to retain for the remainder of 2007. We do not anticipate any significant production increases from the Barnett Shale during the remainder of 2007, although production should not decline significantly with the ongoing activity of three drilling rigs.

The decrease in onshore Louisiana production in 2007 is due primarily to the expected relatively rapid depletion of wells in this area. Since 2005 we have focused less of our spending in this area and therefore drilled fewer wells than we have historically. We are pursuing the potential divesture of these assets, excluding any oil fields that could have tertiary oil potential (See “Overview — Potential sale of Louisiana assets”).

The Texas property acquisition we made late in the first quarter of 2007 (see “Overview — Recent Acquisition”) contributed approximately 680 BOE/d to the second quarter 2007 production, shown in the above table.

Our production for the second quarter of 2007 was weighted toward oil (62%), about the same as our proportion of oil production during the second quarter of 2006, as the recent increases in natural gas production in the Barnett Shale area, offset by declines in natural gas production in Louisiana, generally have been matched by increases in our tertiary oil production.

Oil and Natural Gas Revenues: Oil and natural gas revenues for the second quarter of 2007 increased $28.1 million, or 15%, from revenues in the comparable quarter of 2006, as both commodity prices and production were higher. The increase in overall commodity prices in the second quarter of 2007 increased revenues by $5.6 million, or 3%, while the increase in production in the second quarter of 2007 increased oil and natural gas revenues by $22.5 million, or 12%, over the prior year’s second quarter levels. When comparing the respective six month periods, revenues increased $21.7 million, or 6%, as higher production was partially offset by lower commodity prices. The increase in production during the first half of 2007 increased revenues by $36.5 million, or 10%, while the decrease in overall commodity prices during the first half of 2007 decreased oil and natural gas revenues by $14.8 million, or 4% over the prior year’s first half.

DENBURY RESOURCES INC.

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

Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first and second quarters and first six months periods of 2006 and 2007:


	Three Months Ended									Three Months Ended									Six Months Ended
	March 31,									June 30,									June 30,
	2007			2006			% Change			2007			2006			% Change			2007			2006			% Change
Net Realized Prices:
Oil price per Bbl	$	54.57		$	56.75			-4	%	$	63.48		$	64.03			-1	%	$	59.23		$	60.50			-2	%
Gas price per Mcf		6.63			8.68			-24	%		7.71			6.92			11	%		7.20			7.77			-7	%
Price per BOE		49.06			55.01			-11	%		57.02			55.54			3	%		53.24			55.29			-4	%

NYMEX differentials:
Oil per Bbl	$	(3.73	)	$	(6.71	)		-44	%	$	(1.61	)	$	(6.64	)		-76	%	$	(2.47	)	$	(6.58	)		-62	%
Natural Gas per Mcf		(0.51	)		0.78			-165	%		0.07			0.25			-72	%		(0.19	)		0.49			-139	%

Our oil NYMEX differential during the second quarter of 2007 was the lowest in our corporate history. The improved NYMEX differential during 2007 was related to higher prices received for both our light sweet barrels and our sour barrels primarily as a result of NYMEX (WTI) prices being depressed due to lack of available storage capacity in the mid-continent area, an oversupply of crude from Canada, capacity/transportation issues in moving crude oil out of the Cushing, Oklahoma area and unanticipated refinery outages. There are preliminary indications that this trend is reversing itself in the third quarter and that our differentials have begun to return to historic levels, based on prices to date during July 2007.

Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during a month as most of our natural gas is sold on an index price that is set near the first of the month. While the percentage change in the above table is quite large, these differentials are very seldom more than a dollar above or below the NYMEX amount.

Oil and Natural Gas Derivative Contracts: During the first half of 2007, although we had significant fluctuations related to our non-cash mark-to-market value adjustments in our oil and natural gas derivative contracts (a $35.2 million expense in the first quarter and income of $13.3 million in the second quarter) (see also “Overview — Results of Operations” and “Market Risk Management”), we had net positive cash receipts during each quarter in 2007 from these derivative contracts. We received approximately $8.3 million in net settlements during the first quarter of 2007 and approximately $1.7 million during the second quarter, primarily related to our 2007 natural gas swaps. In comparison, we paid out approximately $0.8 million during the first quarter of 2006 and $2.2 million during the second quarter of 2006 related to our oil swaps in existence at that time.

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

During the second quarter of 2007, operating costs averaged $15.00 per BOE, up from $12.24 per BOE in the second quarter of 2006, and up from the $14.66 per BOE in the first quarter of 2007. Operating expenses on our tertiary operations increased from $17.41 per BOE in the second quarter of 2006 to $20.47 per BOE during the second quarter of 2007, as a result of the increased number of tertiary floods in their initial stages. Tertiary operating expenses were particularly impacted by higher power and energy costs, expenses on new floods in the initial stages of their production response, and payments on leased facilities and equipment (see “CO₂ Operations” above). Our emphasis on tertiary operations is expected to continue, which may further increase our cost per BOE as tertiary production becomes a more significant portion of our total production and operations. The trends were similar when comparing the respective first half periods.

DENBURY RESOURCES INC.

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

Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes and therefore were higher in the second quarter of 2007 than in the comparable quarter of 2006. Transportation and plant processing fees were approximately $1.7 million higher in the second quarter of 2007 than in the second quarter of 2006 and approximately $3.2 million higher for the first half of 2007 than in the first half of 2006.

General and Administrative Expenses

Net general and administrative (“G&A”) expenses decreased 20% between the respective second quarters and 5% between the respective first six months, as set forth below:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Net G&A expense (thousands)
Gross G&A expenses	$	28,372		$	27,255		$	55,142		$	48,595
State franchise taxes		740			282			1,458			694
Operator labor and overhead recovery charges		(14,894	)		(11,176	)		(28,700	)		(21,085	)
Capitalized exploration and development costs		(2,524	)		(1,787	)		(4,772	)		(3,763	)

Net G&A expense	$	11,694		$	14,574		$	23,128		$	24,441

Average G&A cost per BOE	$	3.07		$	4.27		$	3.18		$	3.70
Employees as of June 30		672			550			672			550

Gross G&A expenses increased $1.1 million, or 4%, between the respective second quarters and $6.5 million and 13% between the respective first six months. These increases are primarily due to higher compensation and personnel related costs caused by an increase in the number of employees, higher wages resulting from the 5% mid-year pay increase for all employees in mid-2006, and 2006 year end pay increases which averaged 4.4%. During 2006, we increased our employee count by 30% and we further increased our employee count 13% in the first half of 2007. Partially offsetting these overall compensation increases was a $5.3 million charge to earnings in the second quarter of 2006 related to the modification of the vesting terms of certain restricted stock and stock options previously granted to our former Senior Vice President of Operations, associated with his departure from the Company. Stock compensation expense reflected in gross G&A expenses was approximately $3.0 million in the second quarter of 2007 and $6.1 million for the six months ended June 30, 2007. Stock compensation expense, excluding the $5.3 million charge discussed above, was $3.4 million for the second quarter of 2006 and $6.8 million for the six months ended June 30, 2006. 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 2% pay raise to all employees effective July 1, 2007.

The increase in gross G&A was offset in part by an increase in operator overhead recovery charges in the second quarter and first six months of 2007. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year and increased compensation expense, the amount we recovered as operator overhead charges increased by 33% between the second quarters of 2006 and 2007 and increased by 36% between the first six months of 2006 and 2007. Capitalized exploration costs also increased by 41% between the second quarters of 2006 and 2007 and increased by 27% between the first six months of 2006 and 2007, primarily as a result of increases in personnel and compensation costs.

The net effect was a 20% decrease in net G&A expense between the respective second quarters and a 5% decrease between the first six months of 2007 and 2006. On a per BOE basis, G&A costs decreased 28% in the second quarter of 2007 as compared to levels in the second quarter of 2006, and decreased 14% between the comparative first six months of 2007 and 2006.

DENBURY RESOURCES INC.

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

Interest and Financing Expenses


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Amounts in thousands, except per BOE amounts and interest rates	2007			2006			2007			2006
Cash interest expense	$	12,372		$	8,225		$	22,211		$	16,493
Non-cash interest expense		305			261			574			521
Less: Capitalized interest		(4,321	)		(2,735	)		(8,354	)		(3,009	)

Interest expense	$	8,356		$	5,751		$	14,431		$	14,005

Interest and other income	$	1,764		$	1,469		$	3,547		$	2,844
Average net cash interest expense per BOE (1)	$	1.65		$	1.18		$	1.43		$	1.61
Average interest rate (2)		7.6	%		7.4	%		7.5	%		7.4	%
Average debt outstanding	$	653,303		$	443,786		$	592,284		$	445,361

(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 $2.6 million, or 45%, when comparing the second quarters of 2007 and 2006, and was just slightly higher for the six months ended June 30, 2007 as compared to the prior year six month period. Our average debt levels were significantly higher in the 2007 periods as our debt increased to fund acquisitions of properties in 2006 and 2007 and to fund our budgeted capital spending, which in 2007 is significantly in excess of our cash flow from operations (see also “Capital Resources and Liquidity”). The increase in cash interest expense was partially offset by higher capitalized interest in the 2007 periods as indicated in the above table, due primarily to interest capitalized on our significant unevaluated properties acquired during 2006 and 2007.

Depletion, Depreciation and Amortization


	Three Months Ended				Six Months Ended
	June 30,				June 30,
Amounts in thousands, except per BOE amounts	2007		2006		2007		2006
Depletion and depreciation of oil and natural gas properties	$	40,977	$	32,199	$	76,943	$	61,516
Depletion and depreciation of CO₂ assets		2,762		1,891		5,442		3,680
Asset retirement obligations		756		615		1,486		1,186
Depreciation of other fixed assets		1,740		1,447		3,391		2,513

Total DD&A	$	46,235	$	36,152	$	87,262	$	68,895

DD&A per BOE:
Oil and natural gas properties	$	10.94	$	9.62	$	10.80	$	9.50
CO₂ assets and other fixed assets		1.18		0.98		1.22		0.94

Total DD&A cost per BOE	$	12.12	$	10.60	$	12.02	$	10.44

Our depletion, depreciation and amortization (“DD&A”) rate for oil and natural gas properties on a per BOE basis increased 14% between the respective second quarters and increased 14% between the respective first six months, primarily due to capital spending and increased costs. In the second quarter of 2007, we booked approximately 7.2 million barrels of incremental oil reserves related to our tertiary operations in Soso and Martinville Fields and 10.7 million BOEs of incremental reserves in our Barnett Shale area; however, the future capital costs associated with these additions along with other capital spending and reclassification of costs into our full cost pool resulted in a DD&A rate for our oil and natural gas properties of $10.94 per BOE in the second quarter of 2007 as compared to $10.64 per BOE in the

DENBURY RESOURCES INC.

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

first quarter of 2007 and $10.45 per BOE, in the fourth quarter of 2006. We allocated approximately $36.1 million of the $41.7 million preliminary adjusted purchase price of our March 31, 2007 Seabreeze acquisition to unevaluated properties to reflect the significant probable reserves from future tertiary flooding that we considered to be part of the acquisition. As a result, that acquisition did not materially affect our overall DD&A rate, as the amount included in our full cost pool was at a cost per BOE relatively consistent with our overall DD&A rate. We continually evaluate the performance of our other tertiary projects and if performance indicates that we are reasonably certain of recovering additional reserves from these floods, we recognize those incremental reserves in that quarter. Since we adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change significantly in the future.

Our DD&A rate for our CO₂ and other general corporate fixed assets increased in the first half of 2007 as compared to the rate for the first six months in 2006 as a result of costs incurred drilling CO₂ wells during the past year, putting the Free State CO₂ pipeline into service late in the first quarter of 2006, and higher future development costs, partially offset by an increase in CO₂ reserves from 4.6 Tcf as of December 31, 2005, to 5.5 Tcf as of December 31, 2006 (100% working interest basis before amounts attributable to Genesis’ volumetric production payments).

Income Taxes


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Amounts in thousands, except per BOE amounts and tax rates	2007			2006			2007			2006
Current income tax expense (benefit)	$	7,343		$	(2,349	)	$	8,961		$	7,437
Deferred income tax expense		32,567			31,675			41,581			49,859

Total income tax expense	$	39,910		$	29,326		$	50,542		$	57,296

Average income tax expense per BOE	$	10.46		$	8.60		$	6.96		$	8.68
Effective tax rate		38.9	%		39.9	%		39.0	%		39.4	%

Our income tax provision for the second quarter and first half of 2007 and 2006 was based on an estimated statutory tax rate of approximately 39%, adjusted for the impacts of certain items such as compensation arising from incentive stock options that cannot be deducted for tax purposes in the same manner as the book expense. In both periods, the current income tax expense represents our anticipated alternative minimum cash taxes that we cannot offset with enhanced oil recovery credits. As of December 31, 2006, we had an estimated $41.9 million of enhanced oil recovery credits to carry forward that we can utilize to reduce our current income taxes during 2007. We have not earned any additional credits since 2005 due to the high oil prices, which completely phased out our ability to earn any additional credits.

Per BOE Data

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

DENBURY RESOURCES INC.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Per BOE data	2007			2006			2007			2006
Oil and natural gas revenues	$	57.02		$	55.54		$	53.24		$	55.29
Gain (loss) on settlements of derivative contracts		0.45			(0.65	)		1.37			(0.45	)
Lease operating expenses		(15.00	)		(12.24	)		(14.84	)		(11.80	)
Production taxes and marketing expenses		(2.72	)		(2.77	)		(2.84	)		(2.65	)

Production netback		39.75			39.88			36.93			40.39
Non-tertiary CO₂ operating margin		0.57			0.47			0.63			0.44
General and administrative expenses		(3.07	)		(4.27	)		(3.18	)		(3.70	)
Net cash interest expense		(1.65	)		(1.18	)		(1.43	)		(1.61	)
Current income taxes and other		(1.39	)		2.87			(0.62	)		0.33
Changes in assets and liabilities relating to operations		(7.40	)		(6.56	)		(5.39	)		(4.20	)

Cash flow from operations		26.81			31.21			26.94			31.65
DD&A		(12.12	)		(10.60	)		(12.02	)		(10.44	)
Deferred income taxes		(8.54	)		(9.29	)		(5.73	)		(7.55	)
Non-cash commodity derivative adjustments		3.49			(2.73	)		(3.01	)		(3.06	)
Changes in assets and liabilities and other non-cash items		6.76			4.39			4.72			2.74

Net income	$	16.40		$	12.98		$	10.90		$	13.34

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 $170 million of bank debt outstanding as of June 30, 2007 and $134 million at December 31, 2006. The fair value of the subordinated debt is based on quoted market prices. None of our debt has any triggers or covenants regarding our debt ratings with rating agencies.


	Expected Maturity Dates
							Carrying		Fair
Amounts in thousands	2009		2013		2015		Value		Value
Variable rate debt:
Bank debt	$	170,000	$	—	$	—	$	170,000	$	170,000
(The weighted-average interest rate on the bank debt at June 30, 2007 is 6.3%.)

Fixed rate debt:
7.5% subordinated debt due 2013, net of discount		—		225,000		—		223,883		225,563
(The interest rate on the subordinated debt is a fixed rate of 7.5%)

7.5% subordinated debt due 2015, including premium		—		—		300,000		300,728		300,750
(The interest rate on the subordinated debt is a fixed rate of 7.5%)

Oil and Gas Derivative Contracts

From time to time, we enter into various oil and gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. Historically, we hedged up to 75% of our anticipated production each year to provide us with a reasonably certain amount of cash flow to cover most of our budgeted exploration and development expenditures without incurring significant debt. Since 2005 and beyond, we have entered into fewer derivative contracts, primarily because of our strong financial position resulting from our lower levels of debt relative to our cash flow from operations. We did

DENBURY RESOURCES INC.

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

make an exception in late 2006 when we swapped 80% to 90% of our forecasted 2007 natural gas production at a weighted average price of $7.96 per Mcf. We did this to protect our 2007 projected cash flow, primarily because we currently plan to spend $175 million to $225 million more than we expect to generate in cash flow from operations (see “Capital Resources and Liquidity”) and we did not want to be exposed to the risk of lower natural gas prices.

When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted proved production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. As of June 30, 2007, we had derivative contracts in place related to our $250 million acquisition that closed on January 31, 2006, on which we entered into contracts to cover 100% of the first three years estimated proved producing production at the time we signed the purchase and sale agreement. While these derivative contracts related to the acquisition represent approximately 7% of our estimated 2007 production, they are intended to help protect our acquisition economics related to the first three years of production of the proved producing reserves that we acquired. These swaps cover 2,000 Bbls/d for 2007 at a price of $58.93 per Bbl; and 2,000 Bbls/d for 2008 at a price of $57.34 per Bbl.

At June 30, 2007, our derivative contracts were recorded at their fair value, which was a net liability of approximately $6.1 million, a decrease in value of approximately $21.8 million from the $15.7 million fair value asset recorded as of December 31, 2006. This change is the result of both the expiration of contracts during the first six months of 2007 and the increases in both oil and natural gas commodity futures prices between December 31, 2006 and June 30, 2007.

Based on NYMEX crude oil futures prices at June 30, 2007, oil prices were considerably higher than the swap prices of our outstanding derivative contracts so we would expect to make future cash payments of $15.5 million on our oil commodity hedges. If oil futures prices were to decline by 10%, the amount we would expect to pay under our oil commodity hedges would decrease to $7.6 million, and if futures prices were to increase by 10% we would expect to pay $23.4 million. Based on NYMEX natural gas futures prices at June 30, 2007, we would expect to receive cash payments of $8.8 million on our natural gas commodity hedges. If natural gas prices futures prices were to decline by 10%, we would expect to receive future cash payments of $18.9 million, and if futures prices were to increase by 10% we would expect to pay $1.3 million.

Interest Rate Lock Contracts

At June 30, 2007, the interest rate locks were recorded at their fair value, which was a net asset of approximately $0.2 million. If the 5-year Semi-Annual Swap Rate were to increase or decrease 50-basis points, we would expect the fair value liability to change by approximately $0.9 million, with the increase in rates being a benefit to us and a decrease in rates being a liability to us.

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, 2006.

Forward-Looking Information

The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, cost savings, production rates and volumes or forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values, potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our tertiary operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas, inaccurate cost estimates, fluctuations in the prices of goods and services, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital or its availability, general economic conditions, competition and government regulations, unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or which are otherwise discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings and public statements.

DENBURY RESOURCES INC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Item 4. Controls and Procedures

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

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

Part II. Other Information

Item 1. Legal Proceedings

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

Item 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, 2006. There have been no material changes to the risk factors since the filing of such Form 10-K.

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

ISSUER PURCHASES OF EQUITY SECURITIES


					(c) Total Number of		(d) Maximum Number
	(a) Total				Shares Purchased		of Shares that May
	Number of		(b) Average		as Part of Publicly		Yet Be Purchased
	Shares		Price Paid		Announced Plans or		Under the Plan Or
Period	Purchased		per Share		Programs		Programs
April 1 through 30, 2007		322	$	30.61		—		—
May 1 through 31, 2007		128		33.43		—		—
June 1 through 30, 2007		122		37.15		—		—

Total		572		32.64		—		—

These shares were purchased from employees of Denbury who delivered shares to the company to satisfy their minimum tax withholding requirements related to the Denbury’s stock compensation plans.

Item 3. Defaults Upon Senior Securities

None.

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

Denbury’s Annual Meeting of Stockholders was held on May 15, 2007 for the purposes of (1) electing seven directors, each to serve until their successor is elected and qualified, (2) to increase the number of shares that may be used under our 2004 omnibus stock and incentive plan, (3) to increase the number of shares that may be used under our employee stock purchase plan, and (4) to ratify the appointment by the audit committee of PricewaterhouseCoopers LLP as the Company’s independent auditor for 2007. At the record date, March 30, 2007, 120,737,528 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. Holders of 112,946,582 shares of common stock, representing approximately 92% of the total issued and outstanding shares of common stock, were present in person or by proxy at the meeting to cast their vote.

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


Nominees for Directors	For		Withheld
Ronald G. Greene		108,221,676		4,724,904
David I. Heather		112,408,241		538,334
Greg McMichael		108,421,464		4,525,111
Gareth Roberts		112,581,241		365,334
Randy Stein		112,338,864		607,711
Wieland F. Wettstein		111,850,825		1,095,755
Donald D. Wolf		107,831,953		5,114,622

The proposal regarding an increase to the number of shares that may be used under our 2004 omnibus stock and incentive plan was approved. The votes were cast as follows:

The proposal regarding an increase to the number of shares that may used under our employee stock purchase plan was approved. The votes were cast as follows:

The appointment by the audit committee of PricewaterhouseCoopers LLP as the Company’s independent auditor for 2007 was approved. The votes were cast as follows:

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits:


31(a)*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.


	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

1.		I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the “registrant”);

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

		(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

		(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

		(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

		(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.		The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



August 6, 2007	/s/ Gareth Roberts
	Gareth Roberts
	President and Chief Executive Officer

1.		I have reviewed this quarterly report on Form 10-Q of Denbury Resources Inc. (the “registrant”);

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

		(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

		(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

		(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

		(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.		The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

		(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

		(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Against

Abstentions

Broker Non-Votes


			Page
Part I.	Financial Information

	Item 1.	Financial Statements

		Unaudited Condensed Consolidated Balance Sheets at June 30, 2007 and December 31, 2006		3

		Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2007 and 2006		4

		Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2007 and 2006		5

		Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 30, 2007 and 2006		6

		Notes to Unaudited Condensed Consolidated Financial Statements		7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk		34

	Item 4.	Controls and Procedures		34

Part II.	Other Information

	Item 1.	Legal Proceedings		34

	Item 1A.	Risk Factors		34

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34

	Item 3.	Defaults Upon Senior Securities		34

	Item 4.	Submission of Matters to a Vote of Security Holders		35

	Item 5.	Other Information		35

	Item 6.	Exhibits		35

	Signatures			36
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

		1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

		2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.



Dated: August 6, 2007	/s/ Gareth Roberts
	Gareth Roberts
	President and Chief Executive Officer