e10vq
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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 March 31, 2008
     
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   (I.R.S. Employer
incorporation or organization)   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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ    Accelerated filer o    Non-accelerated filer   o
(Do not check if a smaller reporting company)
  Smaller reporting company 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 April 30, 2008
     
     
Common Stock, $.001 par value   245,992,681
 
 

 


 

INDEX
         
    Page  
Part I. Financial Information
       
 
       
Item 1. Financial Statements
       
 
       
    3  
 
       
    4  
 
       
    5  
 
       
    6  
 
       
    7  
 
       
    16  
 
       
    29  
 
       
    29  
 
       
       
 
       
    29  
 
       
    29  
 
       
    29  
 
       
    29  
 
       
    29  
 
       
    29  
 
       
    30  
 
       
    31  
 Amendment to Sixth Amended and Restated Credit Agreement
 2008 Form of Restricted Stock Award
 2008 Form of Restricted Stock Award
 2008 Form of Performance Share Awards
 2008 Form of Performance Share Awards
 Certification of Chief Executive Officer Pursuant to Section 302
 Certification of Chief Financial Officer Pursuant to Section 302
 Certification of CEO and CFO Pursuant to Section 906

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)
                 
    March 31,     December 31,  
    2008     2007  
Assets
Current assets
               
Cash and cash equivalents
  $ 74,039     $ 60,107  
Accrued production receivable
    142,318       136,284  
Trade and other receivables, net of allowance of $384 and $369
    35,354       28,977  
Derivative assets
          2,283  
Deferred tax assets
    32,583       12,708  
 
           
Total current assets
    284,294       240,359  
 
           
Property and equipment
               
Oil and natural gas properties (using full cost accounting)
               
Proved
    2,735,996       2,682,932  
Unevaluated
    418,129       366,518  
CO2 properties and equipment
    479,138       436,591  
Other
    55,997       50,116  
Less accumulated depletion and depreciation
    (1,193,075 )     (1,143,282 )
 
           
Net property and equipment
    2,496,185       2,392,875  
 
           
Deposits on properties under option or contract
    49,112       49,097  
Other assets
    94,687       88,746  
 
           
Total assets
  $ 2,924,278     $ 2,771,077  
 
           
Liability and Stockholders’ Equity
Current liabilities
               
Accounts payable and accrued liabilities
  $ 144,623     $ 147,580  
Oil and gas production payable
    101,784       84,150  
Derivative liabilities
    64,657       28,096  
Deferred revenue — Genesis
    4,070       4,070  
Short-term capital lease obligations
    980       737  
 
           
Total current liabilities
    316,114       264,633  
 
           
Long-term liabilities
               
Capital lease obligations
    5,248       5,665  
Long-term debt, net of discount or premium
    635,692       674,665  
Asset retirement obligations
    40,153       38,954  
Deferred revenue — Genesis
    23,380       24,424  
Deferred tax liability
    398,894       347,370  
Other
    12,789       10,988  
 
           
Total long-term liabilities
    1,116,156       1,102,066  
 
           
Stockholders’ equity
               
Preferred stock, $.001 par value, 25,000,000 shares authorized; none issued and outstanding
           
Common stock, $.001 par value, 600,000,000 shares authorized; 246,491,237 and 245,386,951 shares issued at March 31, 2008 and December 31, 2007, respectively
    246       245  
Paid-in capital in excess of par
    677,180       662,698  
Retained earnings
    824,181       751,179  
Accumulated other comprehensive loss
    (2,053 )     (1,591 )
Treasury stock, at cost, 589,311 and 637,795 shares at March 31, 2008 and December 31, 2007, respectively
    (7,546 )     (8,153 )
 
           
Total stockholders’ equity
    1,492,008       1,404,378  
 
           
Total liabilities and stockholders’ equity
  $ 2,924,278     $ 2,771,077  
 
           
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Revenues
               
Oil, natural gas and related product sales
  $ 313,197     $ 169,134  
CO2 sales and transportation fees
    2,851       3,091  
Interest income and other
    1,287       1,930  
 
           
Total revenues
    317,335       174,155  
 
           
 
               
Expenses
               
Lease operating expenses
    66,001       50,557  
Production taxes and marketing expenses
    15,186       9,103  
Transportation expense — Genesis
    1,550       1,101  
CO2 operating expenses
    1,143       703  
General and administrative
    16,005       11,434  
Interest, net of interest capitalized of $7,266 and $4,033, respectively
    4,941       6,075  
Depletion, depreciation and amortization
    49,839       41,027  
Commodity derivative expense
    46,781       26,907  
 
           
Total expenses
    201,446       146,907  
 
           
 
               
Income before income taxes
    115,889       27,248  
 
               
Income tax provision
               
Current income taxes
    21,236       1,618  
Deferred income taxes
    21,651       9,014  
 
           
Net income
  $ 73,002     $ 16,616  
 
           
 
               
Net income per common share — basic
  $ 0.30     $ 0.07  
 
               
Net income per common share — diluted
  $ 0.29     $ 0.07  
 
               
Weighted average common shares outstanding
               
Basic
    242,757       237,984  
Diluted
    252,109       247,907  
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Cash flow from operating activities:
               
Net income
  $ 73,002     $ 16,616  
Adjustments needed to reconcile to net cash flow provided by operations:
               
Depreciation, depletion and amortization
    49,839       41,027  
Deferred income taxes
    21,651       9,014  
Deferred revenue — Genesis
    (1,044 )     (956 )
Stock-based compensation
    3,886       2,786  
Non-cash fair value derivative adjustments
    39,128       35,158  
Amortization of debt issue costs and other
    281       582  
Changes in assets and liabilities relating to operations:
               
Accrued production receivable
    (6,034 )     1,480  
Trade and other receivables
    (8,359 )     (8,979 )
Other assets
    (838 )     (22 )
Accounts payable and accrued liabilities
    16,486       (4,986 )
Oil and gas production payable
    17,634       1,429  
Other liabilities
    625       196  
 
           
Net cash provided by operating activities
    206,257       93,345  
 
           
 
Cash flow used for investing activities:
               
Oil and natural gas capital expenditures
    (156,302 )     (139,019 )
Acquisitions of oil and gas properties
    (402 )     (39,137 )
Change in accrual for capital expenditures
    (9,609 )     (4,255 )
Distributions from Genesis
    1,250        
Acquisitions of CO2 assets and CO2 capital expenditures
    (42,526 )     (31,416 )
Net purchases of other assets
    (10,279 )     (897 )
Deposits on properties under option or contract
          (33 )
Increase in restricted cash
    (45 )     (863 )
Net proceeds from sales of properties and equipment
    54,225       5  
 
           
Net cash used for investing activities
    (163,688 )     (215,615 )
 
           
 
               
Cash flow from financing activities:
               
Bank repayments
    (91,000 )      
Bank borrowings
    52,000       96,000  
Payments on capital lease obligations
    (178 )     (161 )
Income tax benefit from equity awards
    5,414       2,560  
Issuance of common stock
    5,154       5,210  
Purchase of treasury stock
    (27 )      
Costs of debt financing
          (205 )
 
           
Net cash provided by (used for) financing activities
    (28,637 )     103,404  
 
           
 
               
Net increase (decrease) in cash and cash equivalents
    13,932       (18,866 )
 
               
Cash and cash equivalents at beginning of period
    60,107       53,873  
 
           
 
Cash and cash equivalents at end of period
  $ 74,039     $ 35,007  
 
           
 
Supplemental disclosure of cash flow information:
               
Cash paid during the period for interest
  $ 2,050     $ 2,379  
Cash paid during the period for income taxes
    2,630       1,038  
Interest capitalized
    7,266       4,033  
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Net income
  $ 73,002     $ 16,616  
Other comprehensive loss, net of income tax:
               
Change in fair value of derivative contracts designated as a hedge, net of tax of ($252) and ($328)
    (480 )     (513 )
Net loss reclassified into income, net of taxes of $11
    18        
 
           
Comprehensive income
  $ 72,540     $ 16,103  
 
           
(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

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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, 2007. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K.
     Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of March 31, 2008 and the consolidated results of its operations and cash flows for the three month periods ended March 31, 2008 and 2007. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.
Stock Split
     On November 19, 2007, stockholders of Denbury Resources Inc. approved an amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 250,000,000 shares to 600,000,00 shares and to split our common stock on a 2-for-1 basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common stock for each share of common stock held at that time. Information pertaining to shares and earnings per share has been retroactively adjusted in the accompanying financial statements and related notes thereto to reflect the stock split.
Net Income Per Common Share
     Basic net income per common share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact on net income and common shares for the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and any other convertible securities outstanding. For the three month periods ended March 31, 2008 and 2007, there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three month periods ended March 31, 2008 and 2007.
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Share amounts in thousands
               
 
               
Weighted average common shares — basic
    242,757       237,984  
Potentially dilutive securities:
               
Stock options and SARs
    7,995       8,675  
Restricted stock
    1,357       1,248  
 
           
Weighted average common shares — diluted
    252,109       247,907  
 
           
     The weighted average common shares — basic amount excludes 2,671,868 shares in 2008 and 3,058,156 shares in 2007 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

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
directly in equity. The dilution impact of these shares on our earnings per share calculation may increase in future periods, depending on the market price of our common stock during those periods.
     For the three months ended March 31, 2008 and 2007, stock options and SARs to purchase approximately 693,000 and 386,000 shares of common stock, respectively, were outstanding but excluded from the diluted net income per common share calculation, as their exercise prices exceeded the average market price of the Company’s common stock during this period and would be anti-dilutive to the calculation.
Recently Adopted Accounting Pronouncement
Fair Value Measurements
     During the first quarter of 2008, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with United States generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. On February 12, 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. This deferral of SFAS No. 157 applies to our asset retirement obligation (“ARO”), which uses fair value measures at the date incurred to determine our liability. However, we do not expect the adoption of SFAS No. 157 to significantly change the methodology we use to estimate the initial fair value of our ARO, because the guidance in SFAS No. 157 is consistent with the fair value guidance in SFAS No. 143, “Accounting for Asset Retirement Obligations” which we apply to determine our ARO.
     As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimizes the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:
     Level 1 — Quoted prices in active markets for identical assets or liabilities as of the reporting date. During the first quarter of 2008 we had no level 1 recurring measurements.
     Level 2 — Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded oil and natural gas derivatives such as over-the-counter swaps.
     Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. During the first quarter of 2008 we had no level 3 recurring measurements.
     The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
                                 
    Fair Value Measurements at March 31, 2008 Using  
            Significant              
    Quoted Prices     Other     Significant        
    in Active     Observable     Unobservable        
    Markets     Inputs     Inputs        
Amounts in thousands   (Level 1)     (Level 2)     (Level 3)     Total  
 
Liabilities:
                               
Oil and Natural Gas Derivative Contracts
  $     $ 62,064     $     $ 62,064  
Interest Rate Lock Contracts
          2,593             2,593  
 
                       
Total
  $     $ 64,657     $     $ 64,657  
 
                       
Recently Issued Accounting Pronouncement
     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of SFAS No. 133.” SFAS No. 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS No. 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS No. 133 have been applied, and the impact that hedges have on an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for us beginning January 1, 2009. We have not yet determined what impact, if any, this pronouncement will have on our disclosures about derivatives.
Note 2. Divestiture
     In October 2007, we entered into an agreement to sell our Louisiana natural gas assets to a privately held company for approximately $180 million (before closing adjustments), plus we retained a net profits interest in one well. In late December 2007, we closed on approximately 70% of that sale with net proceeds of approximately $108.6 million (including estimated final purchase price adjustments). We closed on the remaining portion of the sale in February 2008 and received net proceeds of approximately $48.9 million related to this portion of the asset sale. The agreement has an effective date of August 1, 2007, and consequently operating net revenue after August 1, net of capital expenditures, along with any other minor closing items were adjustments to the purchase price. The potential net profits interest relates to a well in the South Chauvin field and is only earned if operating income from that well exceeds certain levels, which we believe could potentially increase the ultimate value we receive by up to 10%. The operating results of these sold properties are included in our financial statements through the applicable closing dates of the sold properties. We did not record any gain or loss on the sale in accordance with the full cost method of accounting.
Note 3. Asset Retirement Obligations
     In general, our future asset retirement obligations relate to future costs associated with plugging and abandonment of our oil, natural gas and CO2 wells, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2008.
         
    Three Months  
    Ended March 31,  
Amounts in thousands   2008  
Beginning asset retirement obligation
  $ 41,258  
Liabilities incurred and assumed during period
    466  
Revisions in estimated cash flows
    76  
Liabilities settled during period
    (292 )
Accretion expense
    762  
Sales
    (75 )
 
     
Ending asset retirement obligation
  $ 42,195  
 
     
     At March 31, 2008, $2.1 million of our asset retirement obligation was classified in “Accounts payable and accrued liabilities” under current liabilities in our Condensed Consolidated Balance Sheets. Liabilities incurred during the three months ended March 31, 2008 are primarily for oil and natural gas wells drilled during the period. 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 $9.5 million at March 31, 2008 and December 31, 2007 and are included in “Other assets” in our Condensed Consolidated Balance Sheets.
Note 4. Notes Payable and Long-term Indebtedness
                 
    March 31,     December 31,  
Amounts in thousands   2008     2007  
7.5% Senior Subordinated Notes due 2015
  $ 300,000     $ 300,000  
Premium on Senior Subordinated Notes due 2015
    664       685  
7.5% Senior Subordinated Notes due 2013
    225,000       225,000  
Discount on Senior Subordinated Notes due 2013
    (972 )     (1,020 )
Senior bank loan
    111,000       150,000  
Capital lease obligations — Genesis
    5,071       5,238  
Capital lease obligations
    1,157       1,164  
 
           
Total
    641,920       681,067  
Less current obligations
    980       737  
 
           
Long-term debt and capital lease obligations
  $ 640,940     $ 680,330  
 
           
     Effective April 1, 2008, we amended our Sixth Amended and Restated Credit Agreement, the instrument governing our senior bank loan, which increased our borrowing base from $500 million to $1.0 billion. 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 ($1.0 billion), although the banks are not obligated to fund any amount in excess of the commitment amount.
Note 5. Related Party Transactions — Genesis
Interest in and Transactions with Genesis
     Denbury’s subsidiary, Genesis Energy, Inc. is the general partner and owns an aggregate 9.25% interest in Genesis Energy, L.P. (“Genesis”), a publicly traded master limited partnership. Genesis’ business is focused on the mid stream segment of the oil and gas industry in the Gulf Coast area of the United States, and its activities include gathering, marketing and transportation of crude oil and natural gas, refinery services, wholesale marketing of CO2, and supply and logistic services.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     We account for our 9.25% ownership in Genesis under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore we do not consolidate Genesis. Our investment in Genesis is included in “Other assets” in our Condensed Consolidated Balance Sheets. Denbury received cash distributions from Genesis of $1.3 million and $0.3 million during the three months ended March 31, 2008 and 2007, respectively. We also received $30,000 in each of these periods as directors’ fees for certain officers of Denbury that are board members of Genesis. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.
Oil Sales and Transportation Services
     We utilize Genesis’ trucking services and common carrier pipeline to transport certain of our crude oil production to sales points where it is sold to third party purchasers. In the first three months of 2008 and 2007, we expensed $1.5 million and $1.1 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 March 31, 2008 and December 31, 2007, we had $5.1 million and $5.2 million, respectively, of capital lease obligations with Genesis recorded as liabilities in our Condensed Consolidated Balance Sheets.
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 March 31, 2008 and December 31, 2007, $27.4 million and $28.5 million, respectively, was recorded as deferred revenue, of which $4.1 million was included in current liabilities at both March 31, 2008 and December 31, 2007. We recognized deferred revenue of $1.0 million for each of the three months ended March 31, 2008 and 2007, for deliveries under these volumetric production payments. We provide Genesis with certain processing and transportation services in connection with transporting CO2 to their industrial customers for a fee of approximately $0.18 per Mcf of CO2. For these services, we recognized revenues of $1.3 million and $1.1 million for the three months ended March 31, 2008 and 2007, respectively.
Note 6. Derivative Instruments and Hedging Activities
Oil and Gas Derivative Contracts
     We do not apply hedge accounting treatment to our oil and natural gas derivative contracts and therefore the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown under “Commodity derivative expense” in our Condensed Consolidated Statements of Operations.
     The following is a summary of “Commodity derivative expense” included in our Condensed Consolidated Statements of Operations:
                 
    Three Months Ended March 31,  
Amounts in thousands   2008     2007  
Receipt (payment) on settlements of derivative contracts — Oil
  $ (7,392 )   $ 126  
Receipt (payment) on settlements of derivative contracts — Gas
    (656 )     8,125  
Fair value adjustments to derivative contracts — expense
    (38,733 )     (35,158 )
 
           
Commodity derivative expense
  $ (46,781 )   $ (26,907 )
 
           

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Oil and Natural Gas Commodity Derivative Contracts at March 31, 2008:
Crude Oil Contracts at March 31, 2008:
                         
                    Estimated  
    NYMEX Contract Prices Per Bbl     Fair Value Liability  
                    at March 31, 2008  
Type of Contract and Period       Bbls/d   Swap Price     (In Thousands)  
Swap Contracts
                       
April 2008 — Dec. 2008
    2,000     $ 57.34     $ (22,976 )
 
Natural Gas Contracts at March 31, 2008:
                    Estimated
    NYMEX Contract Prices Per MMBtu   Fair Value Liability
                    at March 31, 2008
Type of Contract and Period   MMBtu/d   Swap Price   (In Thousands)
Swap Contracts
                       
April 2008 — Dec. 2008
    20,000     $ 7.89     $ (13,157 )
April 2008 — Dec. 2008
    20,000       7.91       (13,047 )
April 2008 — Dec. 2008
    20,000       7.94       (12,884 )
     At March 31, 2008, our oil and natural gas derivative contracts were recorded at their fair value, which was a net liability of $62.1 million.
Interest Rate Lock Derivative Contracts
     In January 2007, we entered into interest rate lock contracts to remove our exposure to possible interest rate fluctuations related to our commitment to the sale-leaseback financing of certain equipment for CO2 recycling facilities at our tertiary oil fields. We are applying hedge accounting to these contracts as provided under SFAS No. 133. For these instruments designated as interest rate hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Amounts representing hedge ineffectiveness are recorded in earnings. Hedge effectiveness is assessed quarterly based on the total change in the contract’s fair value.
     At March 31, 2008, the interest rate lock contracts have a fair value liability of approximately $2.6 million that was recorded in our March 31, 2008 Condensed Consolidating Balance Sheet. At March 31, 2008, $2.1 million (net of taxes of $1.3 million) is included in “Accumulated other comprehensive loss” in our Condensed Consolidating Balance Sheet associated with these accounting hedges and approximately $0.4 million was expensed in the first quarter of 2008 for ineffectiveness or hedges that no longer qualified for hedge accounting.
Note 7. Condensed Consolidating Financial Information
     Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of Denbury Resources Inc.’s subsidiaries other than minor subsidiaries, except that with respect to our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our equity interest in Genesis are reflected through the equity method by one of our subsidiaries, Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100% owned, directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
                                         
    March 31, 2008  
    Denbury     Denbury                      
    Resources Inc.     Onshore, LLC     Other             Denbury  
    (Parent and     (Issuer and     Guarantor             Resources Inc.  
Amounts in thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Eliminations     Consolidated  
Assets                                        
Current assets
  $ 455,850     $ 277,903     $ 10,597     $ (460,056 )   $ 284,294  
Property and equipment
          2,496,176       9             2,496,185  
Investment in subsidiaries (equity method)
    1,034,633             979,138       (2,013,771 )      
Other assets
    303,105       85,463       56,036       (300,805 )     143,799  
 
                             
Total assets
  $ 1,793,588     $ 2,859,542     $ 1,045,780     $ (2,774,632 )   $ 2,924,278  
 
                             
 
                                       
Liabilities and Stockholders’ Equity
                                       
Current liabilities
  $     $ 765,059     $ 11,111     $ (460,056 )   $ 316,114  
Long-term liabilities
    301,580       1,115,345       36       (300,805 )     1,116,156  
Stockholders’ equity
    1,492,008       979,138       1,034,633       (2,013,771 )     1,492,008  
 
                             
Total liabilties and stockholders’ equity
  $ 1,793,588     $ 2,859,542     $ 1,045,780     $ (2,774,632 )   $ 2,924,278  
 
                             
                                         
    December 31, 2007  
    Denbury     Denbury                      
    Resources Inc.     Onshore, LLC     Other             Denbury  
    (Parent and     (Issuer and     Guarantor             Resources Inc.  
Amounts in thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Eliminations     Consolidated  
Assets                                        
Current assets
  $ 430,518     $ 237,273     $ 7,263     $ (434,695 )   $ 240,359  
Property and equipment
          2,392,865       10             2,392,875  
Investment in subsidiaries (equity method)
    961,990             905,796       (1,867,786 )      
Other assets
    312,556       78,230       57,226       (310,169 )     137,843  
 
                             
Total assets
  $ 1,705,064     $ 2,708,368     $ 970,295     $ (2,612,650 )   $ 2,771,077  
 
                             
 
                                       
Liabilities and Stockholders’ Equity
                                       
Current liabilities
  $     $ 691,062     $ 8,266     $ (434,695 )   $ 264,633  
Long-term liabilities
    300,686       1,111,510       39       (310,169 )     1,102,066  
Stockholders’ equity
    1,404,378       905,796       961,990       (1,867,786 )     1,404,378  
 
                             
Total liabilties and stockholders’ equity
  $ 1,705,064     $ 2,708,368     $ 970,295     $ (2,612,650 )   $ 2,771,077  
 
                             

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
                                         
    Three Months Ended March 31, 2008  
    Denbury     Denbury                      
    Resources Inc.     Onshore, LLC     Other             Denbury  
    (Parent and Co-     (Issuer and Co-     Guarantor             Resources Inc.  
Amounts in thousands   Obligor)     Obligor)     Subsidiaries     Eliminations     Consolidated  
Revenues
  $ 5,625     $ 311,619     $ 5,716     $ (5,625 )   $ 317,335  
Expenses
    5,745       194,897       6,429       (5,625 )     201,446  
 
                             
Income before the following:
    (120 )     116,722       (713 )           115,889  
Equity in net earnings of subsidiaries
    73,104             73,805       (146,909 )      
 
                             
Income before income taxes
    72,984       116,722       73,092       (146,909 )     115,889  
Income tax provision (benefit)
    (18 )     42,917       (12 )           42,887  
 
                             
Net income
  $ 73,002     $ 73,805     $ 73,104     $ (146,909 )   $ 73,002  
 
                             
                                         
    Three Months Ended March 31, 2007  
    Denbury     Denbury                      
    Resources Inc.     Onshore, LLC     Other             Denbury  
    (Parent and Co-     (Issuer and Co-     Guarantor             Resources Inc.  
Amounts in thousands   Obligor)     Obligor)     Subsidiaries     Eliminations     Consolidated  
Revenues
  $ 2,813     $ 173,992     $ 163     $ (2,813 )   $ 174,155  
Expenses
    2,904       146,202       614       (2,813 )     146,907  
 
                             
Income before the following:
    (91 )     27,790       (451 )           27,248  
Equity in net earnings of subsidiaries
    16,703             17,198       (33,901 )      
 
                             
Income before income taxes
    16,612       27,790       16,747       (33,901 )     27,248  
Income tax provision (benefit)
    (4 )     10,592       44             10,632  
 
                             
Net income
  $ 16,616     $ 17,198     $ 16,703     $ (33,901 )   $ 16,616  
 
                             

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
                                         
    Three Months Ended March 31, 2008  
    Denbury     Denbury                      
    Resources Inc.     Onshore, LLC     Other             Denbury  
    (Parent and Co-     (Issuer and Co-     Guarantor             Resources Inc.  
Amounts in thousands   Obligor)     Obligor)     Subsidiaries     Eliminations     Consolidated  
Cash flow from operations
  $ (10 )   $ 205,010     $ 1,257     $     $ 206,257  
Cash flow from investing activities
    (10,541 )     (163,688 )           10,541       (163,688 )
Cash flow from financing activities
    10,541       (28,637 )           (10,541 )     (28,637 )
 
                             
Net increase (decrease) in cash
    (10 )     12,685       1,257             13,932  
Cash, beginning of period
    34       58,343       1,730             60,107  
 
                             
Cash, end of period
  $ 24     $ 71,028     $ 2,987     $     $ 74,039  
 
                             
                                         
    Three Months Ended March 31, 2007  
    Denbury     Denbury                      
    Resources Inc.     Onshore, LLC     Other             Denbury  
    (Parent and Co-     (Issuer and Co-     Guarantor             Resources Inc.  
Amounts in thousands   Obligor)     Obligor)     Subsidiaries     Eliminations     Consolidated  
Cash flow from operations
  $ 33     $ 93,074     $ 238     $     $ 93,345  
Cash flow from investing activities
    (7,770 )     (215,615 )           7,770       (215,615 )
Cash flow from financing activities
    7,770       103,404             (7,770 )     103,404  
 
                             
Net increase (decrease) in cash
    33       (19,137 )     238             (18,866 )
Cash, beginning of period
    1       52,225       1,647             53,873  
 
                             
Cash, end of period
  $ 34     $ 33,088     $ 1,885     $     $ 35,007  
 
                             

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DENBURY RESOURCES INC.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     You should read the following in conjunction with our financial statements contained herein and in our Form 10-K for the year ended December 31, 2007, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K.
     We are a growing independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest carbon dioxide (“CO2”) reserves east of the Mississippi River used for tertiary oil recovery, and hold significant operating acreage onshore Louisiana, in Alabama, in the Barnett Shale play near Fort Worth, Texas, and properties in Southeast Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, including secondary and tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have four primary field offices located in Laurel, Mississippi; McComb, Mississippi; Brandon, Mississippi; and Cleburne, Texas.
Overview
     Operating results. During the first quarter of 2008 our production averaged 44,900 BOE/d, approximately the same as fourth quarter 2007 production after adjusting for the sale of our Louisiana natural gas properties in December 2007 and February 2008, and a 17% increase over production levels in the first quarter of 2007 (a 33% increase after adjusting for the Louisiana natural gas properties sale). Commodity prices continued to increase during the first quarter of 2008, resulting in a 56% increase in our average per BOE price received over prices received in the first quarter of 2007 and a 12% increase over fourth quarter of 2007 average per BOE price received. As a result of the higher prices, we recognized a $38.7 million non-cash fair value charge in the first quarter of 2008 on our oil and natural gas derivative contracts, and in addition, made cash payments of $8.0 million on our derivative contract settlements in the first quarter of 2008, primarily related to our 2008 oil swaps. This compares to a $35.2 million non-cash fair value charge in the first quarter of 2007 and net cash receipts of $8.3 million during that same period.
     All of our expenses, other than interest expense, increased on both an absolute and per BOE basis during the first quarter of 2008 due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), and (iii) higher compensation expense resulting from additional employees and increased salaries, which we consider necessary in order to remain competitive in the industry. In addition, the sale of our Louisiana natural gas properties, which had lower operating costs per BOE, increased our operating cost per BOE by over $1.00, based on 2007 average costs. Even though our average debt level was 25% higher in the first quarter of 2008 as compared to levels in the first quarter of 2007, because of the significant expenditures made during 2007 and 2008 on unevaluated properties, we capitalized $7.3 million of interest expense in the first quarter of 2008 related to those unevaluated properties, as compared to $4.0 million of interest capitalized during the first quarter of 2007, reducing our overall interest expense between the two periods by 19%. The net result was net income of $73.0 million during the first quarter of 2008 as compared to $16.6 million of net income during the first quarter of 2007.
     While overall costs were higher in 2008’s first quarter than in the prior first quarter period, the rate of inflation in our industry during 2007 appears to have moderated for some goods and services, but is increasing rapidly for other goods, an example being steel prices. Likewise, the availability of goods and services is mixed, with improvements in some areas such as rig availability, but still long lead times for certain items, as for example, compressors used in our tertiary recycle facilities and construction services for pipelines. It is difficult to forecast price trends and supply and service availability, which if adverse, can significantly impact both operating costs and capital expenditures, as well as cause delays in achieving our anticipated production targets.
     Overview of tertiary operations. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of 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 2007 Form 10-K for further information regarding these operations, their potential, and the ramifications of this focus.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Oil production from our tertiary operations averaged 17,156 BOE/d in the first quarter of 2008, a 46% increase over our first quarter 2007 tertiary production average of 11,779 BOE/d. This increase resulted from production increases during 2007 in almost every tertiary field except Little Creek Field as more completely described in our 2007 Form 10-K. However, tertiary oil production was slightly lower than our fourth quarter 2007 tertiary production level of 17,428 BOE/d as a result of various operational issues and delays, coupled with normal and expected fluctuations in the forecasted production growth curve.
     Sale of Louisiana Natural Gas Assets. We completed the remaining 30% of the sale of our Louisiana natural gas assets in February with additional proceeds received at that time of approximately $48.9 million, the prior 70% of which closed in December 2007. Production attributable to the sold properties averaged 302 BOE/d (approximately 81% natural gas) during the first quarter of 2008, representing the production prior to the closing date for the portion of the sale that closed in February. Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82% natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth quarter production and approximately 4% of our total proved reserve quantities as of December 31, 2006.
     Genesis Transactions. The Company continues to work toward closing its contemplated transactions with Genesis involving the Company’s NEJD and Free State CO2 Pipelines, including a long-term transportation service arrangement for the Free State line and a 20-year financing lease for the NEJD system. In these transactions, Denbury expects to receive from Genesis $225 million in cash and $25 million of Genesis common limited partnership units at the average closing price of the units over the thirty days prior to closing. The Company anticipates capitalizing these transactions for accounting purposes and currently projects that it will initially pay Genesis approximately $30 million per annum under the financing lease and transportation services agreement (a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline payments fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State Pipeline dependant on the volumes of CO2 transported therein. While the business terms of the transactions have been substantially completed, closing remains subject to finalization of legal issues primarily with Genesis lenders, and completion and delivery of closing documentation.
Capital Resources and Liquidity
     Our current 2008 capital exploration and development budget is approximately $900 million, excluding any potential acquisitions. The current 2008 program includes an estimated $245 million to acquire pipe and right-of-ways for our proposed CO2 pipeline from Louisiana to Texas (the “Green Pipeline”) and another $80 million for the segment of the Delta CO2 Pipeline from Tinsley to Delhi Fields. We expect to spend an additional $450 million constructing the Green Pipeline during 2009, making our current anticipated total cost for that line approximately $700 million. Currently, over 50% of the remaining portion of our 2008 budget is expected to be spent on other tertiary related operations, over 25% in the Barnett Shale area, and the balance in other areas.
     Last fall when we set our initial 2008 capital budget, our capital budget was forecasted to be significantly in excess of our projected cash flow from operations. However, with the significant increases in commodity prices since that time and based on oil and natural gas commodity prices as of late April 2008, we currently project that our 2008 cash flow should be sufficient to fund most, if not all, of our current 2008 capital budget. We are still working to close the anticipated pipeline transactions with Genesis (see “Overview — Genesis Transactions”), which if consummated, will provide us with $225 million of additional long-term financing and it is possible that we could generate additional funds through supplemental transactions with Genesis late in 2008 relating to our Delta CO2 Pipeline, or portions thereof. These potential incremental funds from Genesis would provide us with a significant cushion should commodity prices significantly decrease from current levels during the remainder of the year. Even if these Genesis transactions are not consummated, we have significant availability under our bank credit facility which we could use to fund our expenditures if needed. We could also consider reducing our capital budget if necessary.
     As part of our semi-annual bank review, our bank borrowing base was increased as of April 1, 2008 from $500 million to $1.0 billion as a result of our continued growth, along with the higher commodity prices. 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 ($1.0 billion), although the banks are not

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
obligated to fund any amount in excess of the commitment amount. At April 30, 2008, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and $131 million of bank debt.
     We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, during the last few years as commodity prices have increased, we have increased our capital budget throughout the year. As a result of the recent cost inflation in our industry, many of our recent budget increases have related to escalating costs rather than additional projects. Even though there are signs that this inflationary trend is subsiding, if costs do rise or we spend more than our estimated or forecasted amounts, we will either have to increase our capital budget or consider the elimination of a portion of our planned projects.
     We also continue to pursue additional acquisitions of mature oil fields that we believe have potential as future tertiary flood candidates. These possible acquisitions are difficult to forecast and the purchase price can vary widely depending on the levels of existing production and conventional proved reserves and commodity prices. Any additional acquisitions would be funded, at least temporarily, with bank or other debt, although if significant, the acquisition would likely be ultimately funded with more permanent capital such as subordinated debt and/or additional equity.
Sources and Uses of Capital Resources
                 
Capital Expenditure Summary   Three Months Ended  
    March 31,  
Amounts in thousands   2008     2007  
Oil and gas exploration and development
               
Drilling
  $ 67,291     $ 74,153  
Geological, geophysical and acreage
    4,942       7,540  
Facilities
    44,342       25,710  
Recompletions
    33,744       27,583  
Capitalized interest
    5,983       4,033  
 
           
Total oil and gas exploration and development expenditures
    156,302       139,019  
Oil and gas property acquisitions
    402       39,137  
 
           
Total oil and natural gas capital expenditures
    156,704       178,156  
CO2 capital expenditures, including capitalized interest
    42,526       31,416  
 
           
Total
  $ 199,230     $ 209,572  
 
           
     Our first quarter 2008 capital expenditures were essentially funded with $206.3 million of cash flow from operations, as the $48.9 million of proceeds from the second closing on our Louisiana property sale was used to reduce bank debt by $39.0 million during the first quarter, with the balance of funds from the property sale primarily used to fund other net assets. Our first quarter 2007 capital expenditures were funded with $93.3 million of cash flow from operations, $96.0 million of bank borrowings, $18.9 million of cash and the balance funded with other working capital.
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 which are recorded at fair value in our balance sheets, 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 2007 amounts reflected in our Form 10-K filed in February 2008. 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 2007 Form 10-K for further information regarding our commitments and obligations.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, this shift in focus impacts certain trends in our current and near-term operating results. Please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the section entitled “CO2 Operations” contained in our 2007 Form 10-K for further information regarding these matters.
     During 2008 we plan to drill five additional CO2 source wells to further increase our production capacity and reserves. We estimate that we are currently capable of producing between 850 MMcf/d and 950 MMcf/d of CO2. During the first quarter of 2008 our CO2 production averaged 554 MMcf/d, as compared to an average of approximately 448 MMcf/d during the first quarter of 2007. We used 86% of this production, or 476 MMcf/d, in our tertiary operations during the first quarter of 2008, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.
     Oil production from our tertiary operations averaged of 17,156 BOE/d in the first quarter of 2008, a 46% increase over our first quarter 2007 tertiary production level of 11,779 BOE/d. This increase resulted from production increases during 2007 in almost every tertiary field except Little Creek Field as more completely described in our 2007 Form 10-K. However, tertiary oil production was slightly lower than our fourth quarter 2007 tertiary production level of 17,428 BOE/d as a result of various operational issues and delays, coupled with normal and expected fluctuations in the forecasted production growth curve.
                                           
    Average Daily Production (BOE/d)  
    First     Second     Third     Fourth       First  
    Quarter     Quarter     Quarter     Quarter       Quarter  
Tertiary Oil Field   2007     2007     2007     2007       2008  
Phase I:
                                         
Brookhaven
    1,422       1,794       2,452       2,507         2,638  
Little Creek area
    2,117       1,974       2,011       1,957         1,807  
Mallalieu area
    5,470       5,802       5,823       6,304         6,099  
McComb area
    1,811       1,884       1,853       2,096         1,632  
Phase II:
                                         
Martinville
    320       521       1,101       883         793  
Eucutta
    614       1,338       2,035       2,572         2,699  
Soso
    25       370       826       1,109         1,488  
 
               
Total tertiary oil production
    11,779       13,683       16,101       17,428         17,156  
 
               
     We spent approximately $0.22 per Mcf to produce our CO2 during the first quarter of 2008, higher than our 2007 average of $0.17 per Mcf, primarily due to higher operating costs and increased royalty expense due to higher oil prices in the first quarter of 2008. Due to these same reasons, our estimated total cost per thousand cubic feet of CO2 during the first quarter of 2008 was approximately $0.30, after inclusion of depreciation and amortization expense, also up from the 2007 average of $0.25 per Mcf.
     During the first quarter of 2008, our operating costs for our tertiary properties averaged $20.81 per BOE, higher than the prior year’s first quarter average of $20.27 per BOE, and our fourth quarter 2007 average of $19.90 per BOE. The higher costs are primarily due to general cost inflation in the industry and higher CO2 costs, higher fuel and energy costs and higher rental payments on leased equipment, partially offset by the change in accounting discussed in the below paragraph. We do expect the lease operating expense per BOE for tertiary operations to initially be high, until production increases significantly. For example, for the first quarter of 2008, operating costs per BOE for our Phase I properties, which are generally more developed than our Phase II properties, were $19.85 per BOE, as compared to tertiary operating costs of $23.18 per BOE for Phase II, an area which is just beginning to respond. In comparison, our operating costs for

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Mallalieu Field, currently our highest volume tertiary producer, was $12.68 per BOE during the same period. We expect our operating costs to average between $15 and $20 per BOE over the life of a tertiary flood, even though our recent average tertiary operating costs have been higher because several floods are not yet mature.
     Prior to January 1, 2008, we expensed currently all costs associated with injecting CO2 that we use in our tertiary recovery operations, even though some of these costs were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we began capitalizing, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e. a production response). These capitalized development costs are included in our unevaluated property costs within our full cost pool if there are not already proved tertiary reserves in that field. After we see a production response to the CO2 injections (i.e. the production stage), injection costs will be expensed as incurred, and any previously deferred unevaluated development costs will become subject to depletion upon recognition of proved tertiary reserves. Since we are continuing to initiate new tertiary floods, this means that we are now capitalizing certain costs that we would have expensed historically. Had we continued with the prior accounting methodology of expensing all tertiary injectant costs, we would have expensed an additional $2.9 million or $1.84 per BOE (tertiary properties only), as there were significant injectant costs during the period in new tertiary floods without tertiary related oil production, primarily in the two new tertiary floods at Tinsley and Lockhart Crossing Fields. During the first quarter of 2007, the accounting methodology was not material, as only $116,000 would have been capitalized under the new accounting procedure.
Operating Results
     As summarized in the “Overview” section above and discussed in more detail below, higher commodity prices and higher production in the 2008 period more than offset higher expenses, resulting in significantly higher quarterly earnings.
                 
    Three Months Ended
    March 31,
Amounts in thousands, except per share amounts   2008   2007
Net income
  $ 73,002     $ 16,616  
Net income per common share — basic
    0.30       0.07  
Net income per common share — diluted
    0.29       0.07  
Cash flow from operations
    206,257       93,345  
 

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Certain of our operating results and statistics for the comparative first quarters of 2008 and 2007 are included in the following table.
                 
    Three Months Ended  
    March 31,  
    2008     2007  
 
Average daily production volumes
               
Bbls/d
    30,164       24,054  
Mcf/d
    88,419       85,506  
BOE/d (1)
    44,900       38,305  
 
               
Operating revenues (in thousands)
               
Oil sales
  $ 250,441     $ 118,132  
Natural gas sales
    62,756       51,002  
 
           
Total oil and natural gas sales
  $ 313,197     $ 169,134  
 
           
 
               
Oil and gas derivative contracts (2) (in thousands)
               
Cash receipt (payment) on settlement of derivative contracts
  $ (8,048 )   $ 8,251  
Non-cash fair value adjustment expense
    (38,733 )     (35,158 )
 
           
Total expense from oil and gas derivative contracts
  $ (46,781 )   $ (26,907 )
 
           
 
               
Operating expenses (in thousands)
               
Lease operating expenses
  $ 66,001     $ 50,557  
Production taxes and marketing expenses (3)
    16,736       10,204  
 
           
Total production expenses
  $ 82,737     $ 60,761  
 
           
 
               
Non-tertiary CO2 operating margin (in thousands)
               
CO2 sales and transportation fees (4)
  $ 2,851     $ 3,091  
CO2 operating expenses
    (1,143 )     (703 )
 
           
Non-tertiary CO2 operating margin
  $ 1,708     $ 2,388  
 
           
 
               
Unit prices — including impact of derivative settlements (2)
               
Oil price per Bbl
  $ 88.55     $ 54.63  
Gas price per Mcf
    7.72       7.68  
 
               
Unit prices — excluding impact of derivative settlements (2)
               
Oil price per Bbl
  $ 91.24     $ 54.57  
Gas price per Mcf
    7.80       6.63  
 
               
Oil and gas operating revenues and expenses per BOE (1)
               
Oil and natural gas revenues
  $ 76.65     $ 49.06  
 
           
Oil and gas lease operating expenses
  $ 16.15     $ 14.66  
Oil and gas production taxes and marketing expenses
    4.10       2.96  
 
           
Total oil and gas production expenses
  $ 20.25     $ 17.62  
 
           
 
(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 $1.0 million for both periods associated with volumetric production payments and $1.3 million and $1.1 million for 2008 and 2007, respectively, of transportation income, both from Genesis.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Production: Average daily production by area for each of the quarters of 2007 and the first quarter of 2008 is listed in the following table.
                                           
    Average Daily Production (BOE/d)
    First   Second   Third   Fourth     First
    Quarter   Quarter   Quarter   Quarter     Quarter
Operating Area   2007   2007   2007   2007     2008
           
Mississippi — CO2 floods
    11,779       13,683       16,101       17,428         17,156  
 
                                         
Mississippi — non CO2 floods
    12,738       12,525       12,131       12,530         12,128  
 
                                         
Texas
    6,989       9,048       10,695       13,488         13,522  
 
                                         
Onshore Louisiana
    5,591       5,391       5,546       5,638         905  
 
                                         
Alabama and other
    1,208       1,269       1,247       1,287         1,189  
 
                                         
           
Total Company
    38,305       41,916       45,720       50,371         44,900  
           
     As outlined in the above table, production in the first quarter of 2008 increased 17% over first quarter of 2007 levels but decreased 11% over fourth quarter 2007 levels primarily due to the sale of our onshore Louisiana natural gas properties, of which approximately 70% closed in late December 2007 and approximately 30% in February 2008. The sold Louisiana properties contributed production of 5,097 BOE/d to our fourth quarter of 2007 production and 302 BOE/d to our first quarter of 2008 production, representing the production from those sold properties prior to their closing dates in December 2007 and February 2008. The sale accounts for almost all of the production fluctuations in the onshore Louisiana area above.
     Excluding the Louisiana property sale, the production increase from the first quarter of 2007 is primarily due to increased production from our tertiary operations and from the Barnett Shale, offset in part by decreases in our Mississippi-non CO2 floods. The increase in our tertiary operations is discussed above under “Results of Operations — CO2 Operations.”
     Production in the Mississippi — non-CO2 floods area decreased from the prior year’s first quarter as this area is generally on a gradual decline due to normal depletion; however, our drilling activity in the Heidelberg area Selma Chalk (natural gas) has helped offset the gradual declines in oil production.
     Our Barnett Shale production increased approximately 84% from the prior year’s first quarter level due to our successful drilling activity. During 2006 and 2007, we drilled between 45 and 50 wells each year and we plan to do the same in 2008. Since these wells are characterized by high depletion rates, particularly in their first year of production, we anticipate that our production there during 2008 will be relatively flat to that in the fourth quarter of 2007 production levels at this drilling pace. This trend is evident in that the Barnet Shale production was almost the same in the first quarter of 2008 (12,801 BOE/d) as it was during the fourth quarter of 2007 (12,729 BOE/d), although both are significantly higher than a year ago. The Texas property acquisition we made late in the first quarter of 2007 contributed approximately 721 BOE/d to the first quarter 2008 production.
     Oil and Natural Gas Revenues: Oil and natural gas revenues for the first quarter of 2008 increased $144.1 million, or 85%, from revenues in the first quarter of 2007, due to higher commodity prices and higher production. The increase in overall commodity prices in the first quarter of 2008 increased revenues by $112.8 million, or 67%, when compared to revenues in the first quarter of 2007, while the increase in production in the first quarter of 2008 increased oil and natural gas revenues by $31.3 million, or 18%, as compared to the prior year’s first quarter. Our realized natural gas prices (excluding derivative contracts) for the first quarter of 2008 averaged $7.80 per Mcf, an 18% increase from the average of $6.63 per Mcf realized during the first quarter of 2007, and our realized oil prices (excluding derivative contracts) for the first quarter of 2008 averaged $91.24 per Bbl, a 67% increase from the $54.57 per Bbl average realized in the first quarter of 2007.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
On a combined per BOE basis, our realized commodity prices were 56% higher in the first quarter of 2008 than in the first quarter of 2007.
     Excluding any impact of our hedging activities, our net realized commodity prices and NYMEX differentials were as follows during the first three months of 2008 and 2007.
                 
    Three Months Ended
    March 31,
    2008   2007
Net Realized Prices:
               
Oil price per Bbl
  $ 91.24     $ 54.57  
Gas price per Mcf
    7.80       6.63  
Price per BOE
    76.65       49.06  
 
               
NYMEX Differentials:
               
Oil per Bbl
  $ (6.50 )   $ (3.73 )
Natural Gas per Mcf
    (0.90 )     (0.51 )
     Our oil NYMEX differential during the first three quarters 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. This trend reversed itself by the fourth quarter of 2007, with average NYMEX oil differentials during that quarter of $(7.27) per Bbl, higher than our historical averages due to the significant increase in liquids extracted from our natural gas production in the Barnett Shale, which is recorded as oil production, but sells at a significant discount to NYMEX. The differentials for the first quarter of 2008 improved slightly over fourth quarter of 2007 levels due to normal market fluctuations and minor improvements in certain oil contracts and slightly less Barnett Shale liquid production.
     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. The sale of our Louisiana natural gas properties also contributed to a higher or worse differential during the first quarter of 2008, as we typically received higher than NYMEX prices for the natural gas produced from these sold properties.
     Oil and Natural Gas Derivative Contracts: We made cash payments of $8.0 million on settlements of our oil and natural gas derivative contracts during the first quarter of 2008, as compared to net cash receipts of $8.3 million during the first quarter of 2007, a negative differential of $16.3 million. The payments made in the first quarter of 2008 primarily related to the 2,000 Bbl/d oil swaps for 2008 entered into when we made a large acquisition in January 2006. The 2007 receipts primarily related to the 75 MMcf/d of natural gas swaps for calendar 2007 that we entered into in December 2006.
     Our total mark-to-market expense was $38.7 million during the first quarter of 2008, slightly higher than the $35.2 million charge in the first quarter of 2007. Both of the non-cash charges primarily relate to natural gas swaps for that calendar year entered into the year before, and the resultant decline in value for those swaps as a result of an increase in natural gas prices during both first quarters. Because we do not utilize hedge accounting for our commodity derivative contracts, the adjustments in the fair value of these contracts is recognized currently in our income statement. See “Market Risk Management” for additional information regarding our derivative activities and Note 6 to the Condensed Consolidated Financial Statements.
     Production Expenses: Our lease operating expenses increased between the comparable first quarters on both a per BOE basis and in absolute dollars, as a result of (i) our increasing emphasis on tertiary operations (see discussion of those expenses under “CO2 Operations above), (ii) higher overall industry costs, (iii) increased personnel and related costs, (iv) higher fuel and energy costs to operate our properties, and (v) increasing lease payments for certain equipment in our tertiary operating facilities.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     During the first quarter of 2008, operating costs averaged $16.15 per BOE, up from $14.66 per BOE in the first quarter of 2007, and up from $13.78 per BOE in the fourth quarter of 2007. A significant portion of the increase in per BOE expenses in the first quarter of 2008 resulted from the sale of our Louisiana natural gas properties. If the sold properties were excluded from the first quarter of 2007 results, our operating costs during that period would have been approximately $1.41 per BOE higher than reported, or $16.07 per BOE, much more in line with the first quarter of 2008 operating costs per BOE.
     Effective January 1, 2008, we changed the way we account for certain tertiary costs (see “Results of Operations — CO2 Operations” above). Had we continued with the prior accounting methodology of expensing all tertiary injectant costs, we would have expensed an additional $2.9 million, or approximately $0.70 per BOE, as there were significant injectant costs, primarily at two new tertiary floods at Tinsley and Lockhart Crossing Fields which had not yet shown a production response to the CO2 injections.
     Operating expenses on our tertiary operations increased from $21.5 million in the first quarter of 2007 to $32.5 million during the first quarter of 2008, as a result of our increased tertiary activity level. Tertiary operating expenses were particularly impacted by higher power and energy costs, higher costs for CO2 and payments on leased equipment (see “CO2 Operations” above). We expect this increase in tertiary operating costs to continue and to further increase our cost per BOE as tertiary production becomes a more significant portion of our total production and operations.
     Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes and therefore were higher in the first quarter of 2008 than in the comparable quarter of 2007. Transportation and plant processing fees were about $1.7 million higher in the first quarter of 2008 than in the first quarter of 2007, largely associated with the incremental production and incremental plant processing fees related to our Barnett Shale production.
General and Administrative Expenses
     General and administrative (“G&A”) expenses increased 40% between the respective first quarters as set forth below:
                 
    Three Months Ended  
    March 31,  
Amounts in thousands, except per BOE data and employees   2008     2007  
Gross G&A expense
  $ 34,165     $ 26,770  
State franchise taxes
    828       718  
Operator labor and overhead recovery charges
    (15,953 )     (13,806 )
Capitalized exploration and development costs
    (3,035 )     (2,248 )
 
           
Net G&A expense
  $ 16,005     $ 11,434  
 
           
Average G&A cost per BOE
  $ 3.92     $ 3.32  
Employees as of March 31
    701       629  
 
           
     Gross G&A expenses increased $7.4 million, or 28%, between the first quarters of 2007 and 2008. Approximately $7.0 million of the increase in gross G&A expenses is related to increases in compensation and personnel related costs, due primarily to the increase in employees and salary increases, which we consider necessary in order to remain competitive in our industry. During 2007, we increased our employee count by 15% and we further increased our employee count by approximately 2% during the first quarter of 2008. Stock compensation expense reflected in gross G&A expenses was approximately $4.5 million for the first quarter of 2008 and $3.1 million for the first quarter of 2007.
     The increase in gross G&A was offset in part by an increase in operator labor and overhead recovery charges in the first quarter of 2008. Our well operating agreements allow us, as operator, to charge labor to a well and to charge a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 16% between the first quarters of 2007 and 2008. Capitalized exploration and development costs also increased between the comparable periods in 2007 and 2008, primarily due to additional personnel and increased compensation costs.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The net effect was a 40% increase in net G&A expense between the respective first quarters. On a per BOE basis, G&A costs increased 18% in the first quarter of 2008 as compared to levels of those costs in the first quarter of 2007, a lower percentage increase than the increase in gross costs as a result of the higher production levels.
Interest and Financing Expenses
                 
    Three Months Ended  
    March 31,  
Amounts in thousands, except per BOE data   2008     2007  
Cash interest expense
  $ 11,800     $ 9,839  
Non-cash interest expense
    407       269  
Less: Capitalized interest
    (7,266 )     (4,033 )
 
           
Interest expense
  $ 4,941     $ 6,075  
 
           
Interest and other income
  $ 1,287     $ 1,930  
Average net cash interest expense per BOE (1)
  $ 0.84     $ 1.18  
Average debt outstanding
  $ 661,809     $ 530,586  
Average interest rate (2)
    7.1 %     7.4 %
 
           
 
(1)   Cash interest expense less capitalized interest and other income on a BOE basis.
 
(2)   Includes commitment fees but excludes amortization of premium, discount and debt issue costs.
     Interest expense decreased $1.1 million, or 19%, comparing the first quarters of 2007 and 2008, primarily as a result of a $3.2 million increase in capitalized interest between the first quarter of 2007 and 2008. Our interest capitalization increased because of our growing balance of unevaluated property expenditures related to our CO2 tertiary floods without proved reserves, the largest of which is Tinsley Field, and the construction of our new CO2 pipelines. The increase in capitalized interest was partially offset by a 25% increase in our average debt level between the two quarters.
Depletion, Depreciation and Amortization
                 
    Three Months Ended  
    March 31,  
Amounts in thousands, except per BOE data   2008     2007  
Depletion and depreciation of oil and natural gas properties
  $ 44,190     $ 35,966  
Depletion and depreciation of CO2 assets
    3,022       2,680  
Asset retirement obligations
    762       730  
Depreciation of other fixed assets
    1,865       1,651  
 
           
Total DD&A
  $ 49,839     $ 41,027  
 
           
DD&A per BOE:
               
Oil and natural gas properties
  $ 11.00     $ 10.64  
CO2 assets and other fixed assets
    1.20       1.26  
 
           
Total DD&A cost per BOE
  $ 12.20     $ 11.90  
 
           
     Our depletion, depreciation and amortization (“DD&A”) rate on a per BOE basis increased 1% over the fourth quarter of 2007 DD&A rate of $12.05 per BOE, and increased 3% between the respective first quarters, primarily due to capital spending and increased costs and the lack of any significant incremental proved tertiary reserves to date in 2008. During 2007, we initiated floods at Lockhart Crossing (Phase I), Tinsley (Phase III) and Cranfield (Phase IV), but through March 31, 2008 had not seen a production response, nor had we booked any proved tertiary reserves at these fields. We anticipate recording significant additional proved tertiary reserves by the end of 2008. 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

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 decreased in the first quarter of 2008 as compared to the rate in the comparable quarter in 2007, primarily as a result of the capitalization of approximately $759,000 of DD&A costs associated with the CO2 that was injected into new floods, primarily Tinsley and Lockhart Crossing Fields, and DD&A associated with the CO2 pipelines for those fields if the pipeline was exclusive to that field. Commencing January 1, 2008, we began capitalizing costs incurred to inject CO2 into fields that were in the development stage and had not yet shown a production response to the CO2 (see “Results of Operations — CO2 Operations”).
Income Taxes
                 
    Three Months Ended  
    March 31,  
Amounts in thousands, except per BOE amounts and tax rates   2008     2007  
Current income tax expense
  $ 21,236     $ 1,618  
Deferred income tax provision
    21,651       9,014  
 
           
Total income tax provision
  $ 42,887     $ 10,632  
 
           
Average income tax expense per BOE
  $ 10.50     $ 3.08  
Effective tax rate
    37.0 %     39.0 %
 
           
     In the fourth quarter of 2007, we lowered our estimated statutory income tax rate to 38% from 39% as result of our sale of our Louisiana natural gas assets. During the first quarter of 2008, our effective rate was further reduced primarily as a result of higher section 199 deductions because of our higher pretax income. The current tax portion of our income tax expense increased in the first quarter of 2008 as compared to the first quarter of 2007 as a result of the higher pretax income resulting from higher commodity prices and the lack of any taxable deductions on most of our 2008 CO2 pipeline expenditures (a significant portion of our 2008 capital spending) as they will not be placed into service during the current year. In the first quarter of 2007, 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, 2007, we had an estimated $37 million of enhanced oil recovery credits to carry forward that we can utilize to reduce our current income taxes during 2008. 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.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
                 
    Three Months Ended  
    March 31,  
Per BOE data   2008     2007  
Oil and natural gas revenues
  $ 76.65     $ 49.06  
Gain (loss) on settlements of derivative contracts
    (1.97 )     2.39  
Lease operating expenses
    (16.15 )     (14.66 )
Production taxes and marketing expenses
    (4.10 )     (2.96 )
 
           
Production netback
    54.43       33.83  
Non-tertiary CO2 operating margin
    0.42       0.69  
General and administrative expenses
    (3.92 )     (3.32 )
Net cash interest expense
    (0.84 )     (1.18 )
Current income taxes and other
    (4.39 )     0.22  
Changes in assets and liabilities relating to operations
    4.78       (3.16 )
 
           
Cash flow from operations
    50.48       27.08  
DD&A
    (12.20 )     (11.90 )
Deferred income taxes
    (5.30 )     (2.61 )
Non-cash commodity derivative adjustments
    (9.48 )     (10.20 )
Changes in assets and liabilities and other non-cash items
    (5.63 )     2.45  
 
           
Net income
  $ 17.87     $ 4.82  
 
           
Market Risk Management
Debt
     We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. We had $111 million of bank debt outstanding as of March 31, 2008 and $150 million at December 31, 2007. 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. The following table presents the carrying and fair values of our debt as of March 31, 2008, along with average interest rates.
                                         
    Expected Maturity Dates   Carrying   Fair
Amounts in thousands   2011   2013   2015   Value   Value
                     
Variable rate debt:
                                       
Bank debt (weighted average interest rate of 4.1% at March 31, 2008)
  $ 111,000     $     $     $ 111,000     $ 111,000  
Fixed rate debt:
                                       
7.5% subordinated debt due 2013 (fixed rate of 7.5%)
          225,000             224,028       230,063  
7.5% subordinated debt due 2015 (fixed rate of 7.5%)
                300,000       300,664       306,750  
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, 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 enter into natural gas derivative contracts in late 2006 when we swapped 80% to 90% of our forecasted 2007 natural gas

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
production at a weighted average price of $7.96 per Mcf, and in September 2007 we swapped 70% to 80% of our remaining forecasted 2008 natural gas production after the sale of our Louisiana natural gas properties at a weighted average price of $7.91 per Mcf. We did this to protect our 2008 projected cash flow, primarily because we initially planned to spend $200 million to $250 million more than we expected to generate in cash flow from operations and we did not want to be exposed to the risk of potentially lower natural gas prices. As a result of the higher oil prices, we currently anticipate that our cash flow will exceed our current capital budget (see “Capital Resources and Liquidity”).
     When we make a significant acquisition, we generally attempt to hedge a large percentage, up to 100%, of the forecasted proved production for the subsequent one to three years following the acquisition in order to help provide us with a minimum return on our investment. As of March 31, 2008, 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 oil production at the time we signed the purchase and sale agreement. While these derivative contracts related to the acquisition represent less than 10% of our estimated 2008 production, they are intended to help protect our acquisition economics related to the first three years of production from the proved producing reserves that we acquired. These swaps cover 2,000 Bbls/d for 2008 at a price of $57.34 per Bbl.
     At March 31, 2008, our derivative contracts were recorded at fair value, which was a liability of approximately $62.1 million, an increase in liability of approximately $38.8 million from the $23.3 million fair value liability recorded as of December 31, 2007. This change is the result of an increase in oil and natural gas commodity futures prices between December 31, 2007 and March 31, 2008.
     Based on NYMEX crude oil futures prices at March 31, 2008, we would expect to make future cash payments of $23.3 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 $17.8 million, and if futures prices were to increase by 10% we would expect to pay $28.8 million. Based on NYMEX natural gas futures prices at March 31, 2008, we would expect to make future cash payments of $39.3 million on our natural gas commodity hedges. If natural gas futures prices were to decline by 10%, we would expect to make future cash payments of $22.3 million and if futures prices were to increase by 10% we would expect to pay $56.3 million.
Critical Accounting Policies
     For a discussion of our critical accounting policies, which are related to property, plant and equipment, depletion and depreciation, oil and natural gas reserves, asset retirement obligations, income taxes and hedging activities, and which remain unchanged, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2007.
Forward-Looking Information
     The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, cost savings, production rates and volumes or forecasts thereof, hydrocarbon reserves, hydrocarbon or expected reserve quantities and values, potential reserves from tertiary operations, hydrocarbon prices, pricing assumptions based upon current and projected oil and gas prices, liquidity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, future capital expenditures and overall economics and other variables surrounding our tertiary operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas, inaccurate cost estimates, fluctuations in the prices of goods and services, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital or its availability, general economic conditions, competition and government regulations, unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or which are otherwise discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings and public statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
     The information required by Item 3 is set forth under “Market Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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, 2007. There have been no material developments in such legal proceedings since the filing of such Form 10-K.
Item 1A. Risk Factors
     Information with respect to risk factors has been incorporated by reference from Item 1.A. of our Form 10-K for the year ended December 31, 2007. There have been no material changes to the risk factors since the filing of such Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
     None
Item 3. Defaults Upon Senior Securities
     None.
Item 4. Submission of Matters to a Vote of Security Holders
     None.
Item 5. Other Information
     None.

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DENBURY RESOURCES INC.
Item 6. Exhibits
     Exhibits:
     
10(a)*
  Amendment for Increased Borrowing Base from $500 million to $1.0 billion to Sixth Amended and Restated Credit Agreement among Denbury Onshore, LLC, as Borrower, and JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other financial institutions dated as of March 28, 2008.
 
   
10(b)*
  2008 Form of restricted stock award to certain officers that cliff vests on March 31, 2011 pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
 
   
10(c)*
  2008 Form of restricted stock award without change of control vesting to certain officers that cliff vests on March 31, 2011 pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
 
   
10(d)*
  2008 Form of performance share awards to certain officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
 
   
10(e)*
  2008 Form of performance share awards without change of control vesting to certain officers pursuant to 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
 
   
31(a)*
  Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31(b)*
  Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32*
  Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*   Filed herewith.

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DENBURY RESOURCES INC.
SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  DENBURY RESOURCES INC.
(Registrant)

 
 
  By:   /s/ Phil Rykhoek    
    Phil Rykhoek   
    Sr. Vice President and Chief Financial Officer   
 
     
  By:   /s/ Mark C. Allen    
    Mark C. Allen   
    Vice President and Chief Accounting Officer   
 
Date: May 6, 2008

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