10-Q 1 d84009qe10vq.htm FORM 10-Q 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 June 30, 2011
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number:001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
     
Delaware   20-0467835
     
(State or other jurisdictions of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
5320 Legacy Drive
Plano, TX
  75024
     
(Address of principal executive offices)   (Zip Code)
Registrant’s telephone number, including area code: (972) 673-2000
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 Rule 12b-2 of the Exchange Act). 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 August 1, 2011
     
Common Stock, $.001 par value   402,350,295
 
 

 


 

DENBURY RESOURCES INC.
INDEX
         
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 EX-31.1
 EX-31.2
 EX-32
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)
                 
    June 30,     December 31,  
    2011     2010  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $ 121,792     $ 381,869  
Accrued production receivable
    255,034       223,584  
Trade and other receivables, net of allowance of $486 and $456, respectively
    153,018       114,149  
Short-term investments
    88,220       93,020  
Derivative assets
    19,322       24,242  
Deferred tax assets
    22,097       27,454  
 
           
Total current assets
    659,483       864,318  
 
           
 
               
Property and equipment
               
Oil and natural gas properties (using full cost accounting)
               
Proved
    6,508,928       6,042,442  
Unevaluated
    952,452       870,130  
CO2 and other non-hydrocarbon gases properties
    572,957       523,423  
Pipelines and plants
    1,445,214       1,378,239  
Other property and equipment
    138,671       120,641  
Less accumulated depletion, depreciation, amortization, and impairment
    (2,403,741 )     (2,197,517 )
 
           
Net property and equipment
    7,214,481       6,737,358  
 
           
 
               
Derivative assets
    17,609       12,919  
Goodwill
    1,232,418       1,232,418  
Other assets
    215,432       218,050  
 
           
Total assets
  $ 9,339,423     $ 9,065,063  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities
               
Accounts payable and accrued liabilities
  $ 333,953     $ 345,998  
Oil and gas production payable
    172,837       143,145  
Derivative liabilities
    81,627       78,184  
Current maturities of long-term debt
    8,622       7,948  
Other liabilities
    4,070       4,070  
 
           
Total current liabilities
    601,109       579,345  
 
           
 
               
Long-term liabilities
               
Long-term debt, net of current portion
    2,288,112       2,416,208  
Asset retirement obligations
    86,109       81,290  
Derivative liabilities
    3,378       29,687  
Deferred taxes
    1,687,839       1,547,992  
Other liabilities
    24,562       29,834  
 
           
Total long-term liabilities
    4,090,000       4,105,011  
 
           
 
               
Commitments and contingencies (Note 7)
               
 
               
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; 402,508,885 and 400,291,033 shares issued, respectively
    403       400  
Paid-in capital in excess of par
    3,074,335       3,045,937  
Retained earnings
    1,581,198       1,336,142  
Accumulated other comprehensive loss
    (3,429 )     (488 )
Treasury stock, at cost, 193,177 and 78,524 shares, respectively
    (4,193 )     (1,284 )
 
           
Total stockholders’ equity
    4,648,314       4,380,707  
 
           
Total liabilities and stockholders’ equity
  $ 9,339,423     $ 9,065,063  
 
           
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     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Revenues and other income
                               
Oil, natural gas, and related product sales
  $ 591,099     $ 488,028     $ 1,097,291     $ 818,914  
CO2 sales and transportation fees
    5,343       4,690       10,267       9,187  
Gain on sale of interests in Genesis
          (28 )           101,540  
Interest income and other income
    4,955       4,520       8,004       6,390  
 
                       
Total revenues and other income
    601,397       497,210       1,115,562       936,031  
 
                       
 
                               
Expenses
                               
Lease operating expenses
    129,932       127,743       257,029       223,963  
Production taxes and marketing expenses
    39,688       38,100       72,439       57,417  
CO2 discovery and operating expenses
    1,869       1,681       4,023       3,049  
General and administrative
    30,900       31,192       74,746       63,901  
Interest, net of amounts capitalized of $13,194, $23,850, $24,151 and $45,162, respectively
    42,249       43,483       91,026       69,899  
Depletion, depreciation, and amortization
    103,495       129,209       197,089       211,081  
Derivatives income
    (172,904 )     (128,674 )     (2,154 )     (169,899 )
Loss on early extinguishment of debt
    348             16,131        
Transaction and other costs related to the Encore Merger
    2,018       22,784       4,377       67,783  
 
                       
Total expenses
    177,595       265,518       714,706       527,194  
 
                       
 
                               
Income before income taxes
    423,802       231,692       400,856       408,837  
 
                               
Income tax provision
                               
Current income taxes
    12,028       6,941       11,180       7,610  
Deferred income taxes
    152,528       74,422       144,620       150,694  
 
                       
 
                               
Consolidated net income
    259,246       150,329       245,056       250,533  
Less: net income attributable to noncontrolling interest
          (14,962 )           (18,278 )
 
                       
Net income attributable to Denbury stockholders
  $ 259,246     $ 135,367     $ 245,056     $ 232,255  
 
                       
 
                               
Net income per common share
                               
Basic
  $ 0.65     $ 0.34     $ 0.62     $ 0.67  
Diluted
  $ 0.64     $ 0.34     $ 0.61     $ 0.66  
 
                               
Weighted average common shares outstanding
                               
Basic
    398,631       395,548       398,032       345,126  
Diluted
    403,919       400,867       403,703       350,326  
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)
                 
    Six Months Ended  
    June 30,  
    2011     2010  
Cash flows from operating activities
               
Consolidated net income
  $ 245,056     $ 250,533  
Adjustments needed to reconcile to net cash provided by operating activities
               
Depletion, depreciation, and amortization
    197,089       211,081  
Deferred income taxes
    144,620       150,694  
Gain on sale of interests in Genesis
          (101,540 )
Stock-based compensation
    18,132       17,130  
Non-cash fair value derivative adjustments
    (11,508 )     (226,899 )
Loss on early extinguishment of debt
    16,131        
Other, net
    5,755       5,871  
Changes in operating assets and liabilities
               
Accrued production receivable
    (35,068 )     52,075  
Trade and other receivables
    (28,258 )     10,058  
Other assets
    (2,920 )     (3,134 )
Accounts payable and accrued liabilities
    (48,471 )     12,066  
Oil and natural gas production payable
    30,135       11,236  
Other liabilities
    (7,340 )     (4,880 )
 
           
Net cash provided by operating activities
    523,353       384,291  
 
           
 
               
Cash flows used for investing activities
               
Oil and natural gas capital expenditures
    (471,601 )     (317,173 )
Acquisitions of oil and natural gas properties
    (32,482 )     (24,243 )
Cash paid in Encore Merger, net of cash acquired
          (801,489 )
CO2 and other non-hydrocarbon gases capital expenditures
    (31,731 )     (44,274 )
Pipelines and plants capital expenditures
    (98,669 )     (108,177 )
Net proceeds from sales of oil and natural gas properties and equipment
          881,344  
Net proceeds from sale of interests in Genesis
          162,622  
Other
    1,643       (7,224 )
 
           
Net cash used for investing activities
    (632,840 )     (258,614 )
 
           
 
               
Cash flows from financing activities
               
Bank repayments
    (130,000 )     (1,514,000 )
Bank borrowings
    130,000       1,149,000  
Repayment of senior subordinated notes
    (525,000 )     (609,424 )
Premium paid on repayment of senior subordinated notes
    (13,137 )     (7,214 )
Net proceeds from issuance of senior subordinated notes
    400,000       1,000,000  
Net proceeds from issuance of common stock
    9,203       5,540  
Costs of debt financing
    (13,274 )     (76,232 )
ENP distributions to noncontrolling interest
          (12,209 )
Other
    (8,382 )     (14,255 )
 
           
Net cash used for financing activities
    (150,590 )     (78,794 )
 
           
 
               
Net increase (decrease) in cash and cash equivalents
    (260,077 )     46,883  
Cash and cash equivalents at beginning of period
    381,869       20,591  
 
           
Cash and cash equivalents at end of period
  $ 121,792     $ 67,474  
 
           
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     Six Months Ended  
    June 30,     June 30,  
    2011     2010     2011     2010  
Consolidated net income
  $ 259,246     $ 150,329     $ 245,056     $ 250,533  
Other comprehensive income, net of income tax
                               
Net unrealized loss on available-for-sale securities, net of tax of $(4,375) and $(1,824), respectively
    (7,139 )           (2,976 )      
Interest rate lock derivative contracts reclassified to income, net of tax of $10, $10, $21, and $21, respectively
    18       17       35       34  
Change in deferred hedge loss on interest rate swaps, net of tax of $8 and $18, respectively
          (60 )           (87 )
 
                       
Consolidated comprehensive income
    252,125       150,286       242,115       250,480  
Less: comprehensive income attributable to noncontrolling interest
          (14,950 )           (18,235 )
 
                       
Comprehensive income attributable to Denbury stockholders
  $ 252,125     $ 135,336     $ 242,115     $ 232,245  
 
                       
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
Organization and Nature of Operations
     We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.
Interim Financial Statements
     The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements. 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, 2010. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
     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 year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of June 30, 2011, our consolidated results of operations for the three and six months ended June 30, 2011 and 2010, and our consolidated cash flows for the six months ended June 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.
Noncontrolling Interest
     From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP’s general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheets as of December 31, 2010 and June 30, 2011, nor do our Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 or our Unaudited Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2011 include ENP’s results of operations or cash flows. As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010, “Net income attributable to noncontrolling interest” of $15.0 million and $18.3 million, respectively, represents ENP’s results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.
Net Income Per Common Share
     Basic net income per common share is computed by dividing net income attributable to our stockholders 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 of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and six months ended June 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders 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 periods indicated:

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands   2011     2010     2011     2010  
Basic weighted average common shares
    398,631       395,548       398,032       345,126  
Potentially dilutive securities:
                               
Stock options and SARs
    3,946       3,980       4,251       3,835  
Performance equity awards
    23       146       12       312  
Restricted stock
    1,319       1,193       1,408       1,053  
 
                       
Diluted weighted average common shares
    403,919       400,867       403,703       350,326  
 
                       
     Basic weighted average common shares excludes 3.4 million and 3.6 million shares for the three and six months ended ended June 30, 2011, respectively, and 3.5 million and 3.3 million shares for the three and six months ended June 30, 2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, 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 diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.
     The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands   2011     2010     2011     2010  
Stock options and SARs
    2,412       4,223       2,297       4,785  
Restricted stock
    24       35       15       413  
Short-term Investments
     Short-term investments are available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At June 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010. The cost basis of this investment is $93.0 million. We received distributions of $1.7 million and $3.5 million on the Vanguard common units we own for the three and six months ended June 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations. The unrealized loss on our short-term investment of $7.1 million (net of a tax benefit of $4.4 million) and $3.0 million (net of a tax benefit of $1.8 million) for the three and six months ended June 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.
Recently Issued Accounting Pronouncements
     In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend presentation requirements, it will not have a material effect on our consolidated financial statements.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 2. Acquisitions and Divestitures
2010 Merger with Encore Acquisition Company
     On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.
     For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $200.6 million and $260.9 million, respectively, of oil, natural gas sales and related product sales related to the Encore Merger. For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, we recognized $137.8 million and $180.7 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) related to the Encore Merger. We recognized a total of $2.0 million and $22.8 million of transaction and other costs related to the Encore Merger (primarily advisory, legal, accounting, due diligence, integration and severance costs) for the three months ended June 30, 2011 and 2010, respectively, and $4.4 million and $67.8 million of such costs for the six months ended June 30, 2011 and 2010, respectively.
2010 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge
     In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase included a working interest in a gas plant, which is currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also included approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit.
     This acquisition meets the definition of a business under the FASC Business Combinations topic. The following table presents a summary of the preliminary fair value of these Riley Ridge assets acquired and liabilities assumed:
         
In thousands        
Oil and natural gas properties
  $ 19,646  
CO2 and other non-hydrocarbon gases properties
    10,907  
Pipelines and plants
    72,070  
Prepaid construction and drilling costs
    9,346  
Other assets
    19,300  
Asset retirement obligations
    (472 )
Goodwill
    1,460  
 
     
Total
  $ 132,257  
 
     
     On August 1, 2011, we acquired the remaining working interest in Riley Ridge and an additional interest in the adjoining acreage and became the operator of both projects; see Note 8, Subsequent Event, for more information.
Pro Forma Information
     Had the Encore Merger and October 2010 Riley Ridge acquisition both occurred on January 1, 2010, our combined pro forma revenues and net income for the three and six months ended June 30, 2010, would have been as follows:

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
                 
    Pro Forma Results  
    Three Months Ended     Six Months Ended  
In thousands, except per share amounts   June 30, 2010     June 30, 2010  
Pro forma total revenues
  $ 497,210     $ 1,112,481  
Pro forma net income attributable to Denbury stockholders
    135,494       247,423  
Pro forma net income per common share:
               
Basic
  $ 0.34     $ 0.63  
Diluted
    0.34       0.62  
2010 Sale of Interests in Genesis
     In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (“Genesis”), for net proceeds of approximately $84 million. In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.
2010 Sale of Southern Assets
     In May 2010, we sold certain non-strategic legacy Encore properties primarily located in the Permian Basin, the Mid-continent area and the East Texas Basin (the “Southern Assets”) to Quantum Resources Management, LLC for consideration of $892.1 million after closing adjustments. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.
Note 3. Long-Term Debt
     The following table shows the components of our long-term debt:
                 
    June 30,     December 31,  
In thousands   2011     2010  
Bank Credit Agreement
  $     $  
71/2% Senior Subordinated Notes due 2013, including discount of $437
          224,563  
71/2% Senior Subordinated Notes due 2015, including premium of $427
          300,427  
91/2% Senior Subordinated Notes due 2016, including premium of $13,222 and $14,589, respectively
    238,142       239,509  
93/4% Senior Subordinated Notes due 2016, including discount of $19,996 and $22,139, respectively
    406,354       404,211  
81/4% Senior Subordinated Notes due 2020
    996,273       996,273  
6⅜% Senior Subordinated Notes due 2021
    400,000        
Other Subordinated Notes, including premium of $37 and $41, respectively
    3,842       3,848  
NEJD financing
    165,550       167,331  
Free State financing
    80,953       81,188  
Capital lease obligations
    5,620       6,806  
 
           
Total
    2,296,734       2,424,156  
Less current obligations
    (8,622 )     (7,948 )
 
           
Long-term debt and capital lease obligations
  $ 2,288,112     $ 2,416,208  
 
           
     The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes. DRI has no independent assets or operations. All of our 100% owned subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee our senior subordinated debt jointly and severally.
Bank Credit Agreement
     In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders as party thereto (the “Bank Credit Agreement”). Availability under the Bank Credit Agreement is subject to a borrowing base which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Amendment”). The Amendment reconfirms our current borrowing base of $1.6 billion, extends the maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of debt to adjusted EBITDA. Under the Amendment, the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base. The Amendment also prescribes a commitment fee ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base, and adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x.
6⅜% Senior Subordinated Notes due 2021
     In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).
     The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee this debt jointly and severally.
Redemption of our 2013 and 2015 Notes
     On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 2013 Notes and all $300.0 million principal amount of our 2015 Notes. Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. We recognized a $0.3 million and $16.1 million loss during the three and six months ended June 30, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.
Note 4. Derivative Instruments and Hedging Activities
Oil and Natural 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 “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     From time to time, we enter into various oil and natural 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. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
     We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement.
     The following is a summary of “Derivatives expense (income)” included in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands   2011     2010     2011     2010  
Oil
                               
Payment on settlements of derivative contracts
  $ 16,972     $ 13,829     $ 22,000     $ 77,379  
Fair value adjustments to derivative contracts — expense (income)
    (187,194 )     (145,099 )     (20,130 )     (206,920 )
 
                       
Total derivative expense (income) — oil
    (170,222 )     (131,270 )     1,870       (129,541 )
Natural Gas
                               
Receipt on settlements of derivative contracts
    (6,030 )     (16,630 )     (12,646 )     (20,379 )
Fair value adjustments to derivative contracts — expense (income)
    3,348       19,909       8,622       (19,109 )
 
                       
Total derivative expense (income) — natural gas
    (2,682 )     3,279       (4,024 )     (39,488 )
Ineffectiveness on interest rate swaps
          (683 )           (870 )
 
                       
Derivative income
  $ (172,904 )   $ (128,674 )   $ (2,154 )   $ (169,899 )
 
                       

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Commodity Derivative Contracts Not Classified as Hedging Instruments
     The following tables present outstanding commodity derivative contracts with respect to future production as of June 30, 2011:
                                                 
                            NYMEX Contract Prices Per Bbl  
            Type of                     Weighted Average Price        
Year   Months     Contract     Bbls/d     Swap     Floor     Ceiling  
Oil Contracts
                                               
2011
  July - Sept   Swap     625       79.18              
 
          Collar     42,500             70.35       100.09  
 
          Put     6,625             69.53        
 
                                             
 
          Total July - Sept 2011     49,750                          
 
                                             
 
                                               
 
  Oct - Dec   Swap     625       79.18              
 
          Collar     45,500             70.33       101.74  
 
          Put     6,625             69.53        
 
                                             
 
          Total Oct - Dec 2011     52,750                          
 
                                             
 
                                               
2012
  Jan - Mar   Swap     625       81.04              
 
          Collar     52,000             70.00       106.86  
 
          Put     625             65.00        
 
                                             
 
          Total Jan - Mar 2012     53,250                          
 
                                             
 
                                               
 
  Apr-June   Swap     625       81.04              
 
          Collar     53,000             70.00       119.44  
 
          Put     625             65.00        
 
                                             
 
          Total Apr - June 2012     54,250                          
 
                                             
 
                                               
 
  July-Sept   Swap     625       81.04              
 
          Collar     53,000             80.00       128.57  
 
          Put     625             65.00        
 
                                             
 
          Total July - Sept 2012     54,250                          
 
                                             
 
                                               
 
  Oct - Dec   Swap     625       81.04              
 
          Collar     53,000             80.00       128.57  
 
          Put     625             65.00        
 
                                             
 
          Total Oct - Dec 2012     54,250                          
 
                                             

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
                                 
            Type of             Weighted Average Swap  
Year   Months     Contract     MMBtu/d     Price per MMBtu  
Natural Gas Contracts
                               
2011
  July - Sept   Swap     33,500     $ 6.27  
 
                             
 
          Total July-Sept 2011     33,500          
 
                             
 
                               
 
  Oct - Dec   Swap     33,500       6.27  
 
                             
 
          Total Oct - Dec 2011     33,500          
 
                             
 
                               
2012
  Jan - Dec   Swap     20,000       6.53  
 
                             
 
          Total Jan - Dec 2012     20,000          
 
                             
Additional Disclosures about Derivative Instruments
     At June 30, 2011 and December 31, 2010, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:
                         
            Estimated Fair Value  
            Asset (Liability)  
            June 30,     December 31,  
Type of Contract   Balance Sheet Location     2011     2010  
            (In thousands)  
Derivatives not designated as hedging instruments
                       
Derivative asset
                       
Oil contracts
  Derivative assets — current   $ 1,462     $ 3,050  
Natural gas contracts
  Derivative assets — current     17,860       21,192  
Oil contracts
  Derivative assets — long-term     11,281       1,301  
Natural gas contracts
  Derivative assets — long-term     6,328       11,618  
 
                       
Derivative liability
                       
Oil contracts
  Derivative liabilities — current     (67,196 )     (55,256 )
Deferred premiums
  Derivative liabilities — current     (14,431 )     (22,928 )
Oil contracts
  Derivative liabilities — long-term     (2,228 )     (25,906 )
Deferred premiums
  Derivative liabilities — long-term     (1,150 )     (3,781 )
 
                   
Total derivatives not designated as hedging instruments
          $ (48,074 )   $ (70,710 )
 
                   
Note 5. Fair Value Measurements
Fair Value Hierarchy
     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). We utilize 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 minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC 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 are as follows:

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
    Level 1 — Quoted prices in active markets for identical assets or liabilities as of the reporting date.
 
    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 that are based on NYMEX pricing.
 
    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. Instruments in this category include non-exchange-traded natural gas derivatives swaps that are based on regional pricing other than NYMEX (e.g., Houston Ship Channel).
     We adjust the valuations for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and Denbury’s credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
     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 the periods indicated:
                                 
    Fair Value Measurements Using:  
            Significant              
    Quoted Prices     Other     Significant        
    in Active     Observable     Unobservable        
    Markets     Inputs     Inputs        
In thousands   (Level 1)     (Level 2)     (Level 3)     Total  
June 30, 2011
                               
Assets
                               
Short-term investments
  $ 88,220     $     $     $ 88,220  
Oil and natural gas derivative contracts
          30,293       6,638       36,931  
Liabilities
                               
Oil and natural gas derivative contracts
          (69,424 )           (69,424 )
 
                       
Total
  $ 88,220     $ (39,131 )   $ 6,638     $ 55,727  
 
                       
 
                               
December 31, 2010
                               
Assets
                               
Short-term investments
  $ 93,020     $     $     $ 93,020  
Oil and natural gas derivative contracts
          20,683       16,478       37,161  
Liabilities
                               
Oil and natural gas derivative contracts
          (81,162 )           (81,162 )
 
                       
Total
  $ 93,020     $ (60,479 )   $ 16,478     $ 49,019  
 
                       

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     The following table summarizes the changes in the fair value of our Level 3 assets for the three and six months ended June 30, 2011 and 2010:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands   2011     2010     2011     2010  
Balance, beginning of period
  $ 15,346     $ 50,518     $ 16,478     $  
Unrealized gains/(losses) on commodity derivative contracts included in earnings
    (7,386 )     126       (7,076 )     14,899  
Commodity derivative contracts acquired from Encore
                      38,093  
Receipts on settlement of commodity derivative contracts
    (1,322 )     (10,361 )     (2,764 )     (12,709 )
 
                       
Balance, end of period
    6,638       40,283     $ 6,638     $ 40,283  
 
                       
     Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives income” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements:
                                 
    June 30, 2011     December 31, 2010  
    Carrying     Estimated     Carrying     Estimated  
In thousands   Amount     Fair Value     Amount     Fair Value  
71/2% Senior Subordinated Notes due 2013
  $     $     $ 224,563     $ 228,375  
71/2% Senior Subordinated Notes due 2015
                300,427       310,500  
91/2% Senior Subordinated Notes due 2016
    238,142       249,942       239,509       249,661  
93/4% Senior Subordinated Notes due 2016
    406,354       476,446       404,211       475,380  
81/4% Senior Subordinated Notes due 2020
    996,273       1,085,938       996,273       1,080,956  
6⅜% Senior Subordinated Notes due 2021
    400,000       400,000              
     The fair values of our senior subordinated notes are based on quoted market prices. We have other financial instruments consisting primarily of cash, cash equivalents and short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Note 6. Supplemental Information
Accounts Payable and Accrued Liabilities
     The following table summarizes our accounts payable and accrued liabilities as of the periods indicated:
                 
    June 30,     December 31,  
In thousands   2011     2010  
Accounts payable
  $ 72,830     $ 47,660  
Accrued exploration and development costs
    96,910       101,758  
Accrued compensation
    26,760       39,757  
Accrued lease operating expense
    25,100       23,557  
Accrued interest
    61,166       57,077  
Taxes payable
    16,537       34,371  
Other
    34,650       41,818  
 
           
Total
  $ 333,953     $ 345,998  
 
           
Supplemental Cash Flow Information
     The following table sets forth supplemental cash flow information for the periods indicated:
                 
    Six Months Ended  
    June 30,  
In thousands   2011     2010  
Cash paid for interest, expensed
  $ 72,774     $ 43,296  
Cash paid for interest, capitalized
    24,151       45,162  
Cash paid for income taxes
    31,072       11,920  
Cash received for income tax refunds
    20,841       13,093  
Increase in liabilities for capital expenditures
    25,141       46,170  
Issuance of Denbury common stock in connection with the Encore Merger
          2,085,681  

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 7. Commitments and Contingencies
     In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions. Under the three new contracts, Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC’s Medicine Bow Fuel and Power LLC (“MBFP”) project in Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and purchase 100% of the CO2 captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas. These new contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these new sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 200 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the IGCC project by 2014, and 50 MMcf/d of CO2 from Air Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO2 will fluctuate based on the changes in the price of oil.
     As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies. The IGCC and Air Products plants are currently being constructed and MBFP is in the initial stages of construction but its completion is still contingent upon securing debt financing and equity commitments and receipt of all necessary consents and approvals.
     In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. As a result of the prospective nature of the IRS’s determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are subject to review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.
     We are subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. We have received a $15.0 million assessment from the Mississippi taxing authority for use tax, penalties and interest covering the 2004-2007 period. We believe this assessment is significantly in excess of any amounts owed and we are appealing the assessment. We do not believe the outcome of this matter will have a material adverse effect on our financial position or results of operations.
     We are involved in various lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
Note 8. Subsequent Event
     On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $191 million, including a $15 million contingent payment to be paid at the time the property’s gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments including payment for capital expenditures incurred between the effective date of the purchase (April 1, 2011) and closing. We expect the gas processing facility to be operational during the fourth quarter of 2011.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     The acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. We will account for our acquisition of Riley Ridge under the acquisition method of accounting, which will result in the allocation of the purchase price to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition, with the excess purchase price, if any, being recognized as goodwill. We have not yet completed our initial calculation necessary to make this allocation.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2010, 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. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this report, along with Forward-Looking Information at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
     We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest CO2 reserves used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO2 tertiary recovery operations.
     The acquisition of Encore Acquisition Company (the “Encore Merger”) on March 9, 2010, has had a significant impact on nearly every aspect of our business, including oil and natural gas production, revenues and operating expenses. Accordingly, the Encore Merger impacts the comparability of our financial results for the first six months of 2010 to those in the first six months of 2011, which is more fully detailed throughout the following discussion and analysis. Our financial results for the first six months of 2010 include the results of operations of Encore from the date of the acquisition on March 9, 2010 through June 30, 2010. Additionally, starting in May 2010 and throughout the remainder of that year, we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).
     Second Quarter Operating Highlights. We recognized net income of $259.2 million, or $0.65 per basic common share, during the second quarter of 2011 as compared to net income of $135.4 million, or $0.34 per basic common share, during the second quarter of 2010. This increase between the two periods is primarily attributable to:
    A $103.1 million ($63.9 million after tax), or 21%, increase in revenue, made up of $214.4 million of additional revenue from higher realized commodity prices in the 2011 second quarter, partially offset by a decrease of $111.3 million of revenue primarily attributable to the absence in the most recent quarter of production from properties sold starting in May 2010;
 
    A $58.6 million increase in the non-cash fair value adjustment in the mark-to-market valuation of our commodities derivatives, principally attributable to oil futures (non-cash income of $183.8 million in the second quarter of 2011 compared to $125.2 million of such non-cash income in the second quarter of 2010); and
 
    $22.8 million of transaction and other costs related to the Encore Merger incurred in the 2010 period ($14.1 million after tax), which costs were negligible in the most recent quarter.
     During the second quarter of 2011, our oil and natural gas production, which was 92% oil, averaged 64,919 BOE/d compared to 84,111 BOE/d produced during the second quarter of 2010. This drop in production is primarily attributable to the sale of non-strategic legacy Encore assets and our interests in ENP (which together had production of 20,526 BOE/d in last year’s second quarter), which were sold starting in May 2010, partially offset by increases in our quarterly tertiary and Bakken production. Our tertiary oil production averaged 30,771 Bbls/d during the second quarter of 2011, up 8% over the 28,507 Bbls/d during the second quarter a year earlier. Tertiary oil production was essentially flat sequentially (down 0.2%, or 54 Bbls/d) for the second quarter. Our Bakken oil production averaged 7,626 BOE/d during the second quarter of 2011, up 69% over production of 4,500 BOE/d during the second quarter of 2010 and sequentially up 33% from levels in the first quarter of 2011. See Results of Operations — CO2 Operations and Results of Operations — Operating Results — Production for more information.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Oil prices during the second quarter of 2011 were considerably higher than prices during the second quarter of 2010. Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $100.06 per BOE during the second quarter of 2011, compared to $63.76 per BOE during the second quarter of 2010, a 57% increase between the two periods. Including the impact of cash settlements on our commodity derivative contracts, our average oil and natural gas price per BOE was $98.21 per BOE during the second quarter of 2011 compared to $64.13 per BOE during the second quarter of 2010, a 53% increase. During the second quarter of 2011, our oil price differentials (our received net oil price compared to NYMEX West Texas Intermediate (“WTI”) prices) improved significantly from a negative $4.13 per Bbl in the second quarter of 2010 to a positive $3.72 per Bbl in the second quarter of 2011, primarily due to the favorable price differential for crude oil sold under Louisiana Light Sweet (“LLS”) index pricing. See Results of Operations — Operating Results — Oil and Natural Gas Revenues below for more information.
     August 2011 Acquisition of Remaining Working Interest in Riley Ridge. On August 1, 2011, we acquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”) and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $191 million, which includes a $15 million contingent payment to be paid at the time the property’s gas processing facility is operational and meets specific performance conditions, plus customary closing adjustments, including payments for capital expenditures incurred between the effective date of the purchase (April 1, 2011) and closing. We currently expect the gas processing facility to be operational with the first production of natural gas and helium from Riley Ridge during the fourth quarter of 2011. The CO2 will be re-injected into the reservoir until we have completed an additional separation facility and a CO2 pipeline to the field, which is expected to be completed in four or five years.
      Combining this acquisition with the interest in Riley Ridge that we acquired in October 2010, we estimate that our total ownership at Riley Ridge currently contains estimated proved reserves of 435 Bcf of natural gas, 15.5 Bcf of helium and 2.4 Tcf of CO2. The adjacent 28,000 acres is estimated to contain additional probable reserves of 250 to 300 Bcf of natural gas, 9.5 to 11.5 Bcf of helium and 2.0 to 2.2 Tcf of CO2, net to our interest. The first production of natural gas and helium from Riley Ridge is expected to begin late in the fourth quarter of 2011, with initial production of CO2 expected in four to five years following construction of both additional facilities to separate the CO2 from the remaining gas stream, and a CO2 pipeline to the field.
     Addition of Proved Oil and Natural Gas Reserves. We added 30.9 MMBOE of estimated proved reserves during the first six months. These reserve additions include 28.1 MMBOE of estimated proved reserves at our Bakken properties, and minor revisions to our other properties. These additions do not include estimated proved reserves of approximately 250 Bcf of natural gas (41.7 MMBOE) associated with the Riley Ridge acquisitions completed in August discussed above.
     March 2011 CO2 Purchase Contracts. In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions. The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions. We will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC’s Medicine Bow Fuel and Power LLC (“MBFP”) project in Medicine Bow, Wyoming, 70% of the CO2 captured from Mississippi Power Company’s Kemper County Integrated Gasification Combined Cycle (“IGCC”) project in Mississippi, and 100% of the CO2 captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas. These three contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate these three sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf. We expect to begin taking delivery of approximately 200 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the IGCC project in 2014, and 50 MMcf/d of CO2 from Air Products in late 2012. Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price. The purchase price of CO2 will fluctuate based on the changes in the price of oil.
     As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies. Construction on the IGCC and MBFP plants is in the initial stages and additional construction under the MBFP agreement is contingent upon securing debt financing and equity commitments and receipt of all necessary consents and approvals. The Air Products agreement is also contingent upon third party approvals for the necessary utilities and infrastructure.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     February 2011 Debt Refinancing. In February 2011, we issued, at par, $400 million of 6⅜% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to partially fund the repurchase of $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes in cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. In the first quarter of 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par and $220.9 million in principal of the 2015 Notes at 104.125% of par. We redeemed the remaining outstanding 2015 Notes at 103.75% of par during the first quarter of 2011 and all of the remaining outstanding 2013 Notes at par on April 1, 2011. During the three and six months ended June 30, 2011, we recognized $0.3 million and $16.1 million, respectively, of loss associated with the debt repurchases, included in our income statements under the caption “Loss on early extinguishment of debt”.
Capital Resources and Liquidity
     In June 2011, when we signed the agreement to acquire the remaining interest in Riley Ridge, which closed in August 2011, our Board of Directors approved a $50 million increase in our 2011 capital spending budget for development of the Riley Ridge plant, increasing our projected 2011 oil and gas capital investments to $1.35 billion, excluding capitalized interest, tertiary start-up costs, acquisitions and divestitures, and net of equipment leases. Our current 2011 capital budget includes the following:
    $450 million allocated for tertiary oil field expenditures;
 
    $350 million in the Bakken area of North Dakota;
 
    $250 million to be spent on our CO2 pipelines;
 
    $200 million to be spent on CO2 sources in the Jackson Dome and Riley Ridge areas; and
 
    $100 million on drilling, completion and other development activities in our other areas.
     Based on oil and natural gas commodity futures prices in early August 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is $150 million to $250 million greater than our anticipated cash flow from operations. These expenditures will be funded with our excess cash on hand or, if necessary, borrowings under our $1.6 billion Bank Credit Agreement under which at August 4, 2011, we had drawn $125 million, all of which was used as part of the funding of our August 1, 2011 Riley Ridge acquisition discussed above. Another potential source of funds would be proceeds if we should sell the units in Vanguard Natural Resources LLP units acquired in the sale of ENP, which have ranged in value between approximately $80 million and $100 million during the second quarter of 2011.
     We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could impact the timing of our future production. There are potential limitations on the amount of capital spending we can eliminate without penalties (refer to Management’s Discussion and Analysis — Capital Resources and Liquidity — Off-Balance Sheet Arrangements — Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010, and see CO2 Purchase Contracts above and Off-Balance Sheet Arrangements below for further information regarding additional commitments entered into during 2011). In addition to the potential flexibility in our capital spending plans, we have approximately $1.4 billion of unused liquidity under our bank credit line and have significant oil price floors through the end of 2012 (see Note 4 to the Unaudited Condensed Consolidated Financial Statements), which together should provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly.
     Our capital spending estimate also assumes that we fund approximately $60 million of budgeted equipment purchases with operating leases, the amount of which is dependent upon securing acceptable financing. Through August 1, 2011, we have funded approximately $27 million of these budgeted equipment purchases with operating leases. Our net capital expenditures would increase by the amount of any shortfall in operating leases for this purchased equipment, and we anticipate funding any such additional capital expenditures under our Bank Credit Agreement.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     In May 2011, we entered into our Fifth Amendment to the Bank Credit Agreement, reconfirming our current borrowing base of $1.6 billion, extending the maturity from March 2014 to May 2016, reducing certain margins and letter of credit fees, and adjusting the maximum permitted ratio of debt to adjusted EBITDA. See further discussion in Note 3 to the Unaudited Condensed Consolidated Financial Statements.
     Capital Expenditure Summary. The following table of capital expenditures includes accrued capital for the six month periods of 2011 and 2010:
                 
    Six Months Ended  
    June 30,  
In thousands   2011     2010  
Oil and natural gas exploration and development:
               
Drilling
  $ 244,466     $ 155,503  
Geological, geophysical, and acreage
    14,339       15,121  
Facilities
    123,742       73,712  
Recompletions
    104,878       91,534  
Capitalized interest
    18,652       13,681  
 
           
Total oil and natural gas exploration and development expenditures
    506,077       349,551  
CO2 and other non-hydrocarbon gases capital expenditures:
               
Drilling
    28,768       27,113  
Geological, geophysical, and acreage
    10,195       4,299  
Facilities
    13,737       12,245  
 
           
Total CO2 and other non-hydrocarbon gases capital expenditures
    52,700       43,657  
 
           
Pipelines and plants capital expenditures:
               
Pipelines and plants
    61,292       92,500  
Capitalized interest
    5,499       31,481  
 
           
Total pipelines and plants capital expenditures
    66,791       123,981  
 
           
Total capital expenditures excluding acquisitions
    625,568       517,189  
 
           
Oil and natural gas property acquisitions
    32,482       24,243  
Consideration for the Encore Merger(1)
          2,952,515  
 
           
Total
  $ 658,050     $ 3,493,947  
 
           
 
(1)   Consideration given in the Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued.
     Our capital expenditures for the first six months of 2011 were funded with $523.4 million of cash flow from operations and the remainder with cash on hand at the beginning of the period. Our capital expenditures for the first six months of 2010, excluding the Encore Merger, were funded with $384.3 million of cash flow from operations along with proceeds from the sale of our interests in Genesis and the Southern Assets.
     Off-Balance Sheet Arrangements. 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 our proved reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements.
     In April 2011, we entered into three long-term drilling contracts. Our total commitment under these contracts is approximately $93 million, with $9 million expected to be paid during the remainder of 2011, $31 million in both 2012 and 2013, and $22 million in 2014.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     In May 2011, we entered into an agreement with Elk Petroleum to acquire a 65% working interest in Grieve Field, a planned CO2 enhanced oil recovery project located in Wyoming. Denbury will invest the first $28.5 million of capital and operating costs in Phase 1. In Phase 2 of the project, Denbury may fund, at Elk’s option, Elk’s 35% share of the next $34.3 million of capital and operating costs, with Denbury recouping its Phase 2 expenditures (plus interest) out of Elk’s 35% working interest share of production from the project. In connection with that agreement, we were assigned a CO2 purchase and CO2 transportation contract to purchase CO2 reserves from Exxon Mobil Corporation’s La Barge facility and transport the CO2 to Grieve Field beginning in March of 2012. Our annual commitment under the CO2 purchase and transportation contracts is approximately $16 million annually for 2 years and approximately $25 million annually for the remaining 8 years (assuming a $100 per barrel NYMEX oil price).
     Our commitments and obligations consist of those detailed as of December 31, 2010 in our 2010 Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations - Off-Balance Sheet Arrangements — Commitments and Obligations, plus the long-term drilling contracts described above, the Grieve Field obligations detailed above, and the three CO2 purchase contracts entered into during the first quarter of 2011, which CO2 purchase contracts are subject to numerous contingencies, as discussed under Overview — CO2 Purchase Contracts above.
Results of Operations
CO2 Operations
     Our focus on CO2 operations is the primary strategy 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 on Form 10-K for the year ended December 31, 2010 and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the section entitled CO2 Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding these matters.
     During the second quarter of 2011, our CO2 production at Jackson Dome averaged 992 MMcf/d compared to an average of 768 MMcf/d produced during the second quarter of 2010 and 1,021 MMcf/d produced during the first quarter of 2011. We used 91% of this production, or 903 MMcf/d, in our tertiary operations during the second quarter of 2011, and sold the balance to our industrial customers, or to Genesis pursuant to our volumetric production payments. Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Off-Balance Sheet Arrangements — Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion on our CO2 delivery obligations. We recognized a negative proven CO2 reserve revision during the second quarter of approximately 239 Bcf at our Jackson Dome Dri-Dock prospect. This revision was a result of the second well in this formation not being a productive well and analysis of the reprocessed seismic data, which showed incremental faulting in the Dri-Dock reservoir. Even with this downward revision, we still anticipate that we have sufficient CO2 reserves to develop our current Gulf Coast enhanced oil recovery program and we are continuing to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome. At December 31, 2010, our proven CO2 reserves at Jackson Dome were approximately 7.1 Tcf.
     We spent approximately $0.27 per Mcf in operating expenses to produce our CO2 during the first six months of 2011, comprised of $0.25 per Mcf during the first quarter of 2011 and $0.28 per Mcf during the second quarter of 2011. This rate is up significantly from our $0.22 per Mcf cost during the second quarter of 2010, due primarily to increased CO2 royalty expense as a result of higher oil prices (to which CO2 royalties are tied).

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following table summarizes our tertiary oil production and tertiary lease operating expense per Bbl for each quarter in 2010 and the first and second quarters of 2011:
                                                 
    Average Daily Production (Bbls/d)  
    First     Second     Third     Fourth     First     Second  
    Quarter     Quarter     Quarter     Quarter     Quarter     Quarter  
Tertiary Oil Field   2010     2010     2010     2010     2011     2011  
Phase 1:
                                               
Brookhaven
    3,416       3,277       3,323       3,699       3,664       3,213  
McComb area
    2,289       2,160       2,484       2,433       2,161       1,983  
Mallalieu area
    3,443       3,628       3,279       3,164       2,925       2,646  
Other
    2,817       3,282       3,343       3,361       3,290       3,196  
Phase 2:
                                               
Heidelberg
    1,708       1,857       2,806       3,422       3,374       3,548  
Eucutta
    3,792       3,625       3,284       3,286       3,247       3,114  
Soso
    3,213       3,207       3,016       2,828       2,582       2,317  
Martinville
    927       764       606       586       500       416  
Phase 3:
                                               
Tinsley
    4,419       5,248       6,024       6,614       6,567       6,990  
Phase 4:
                                               
Cranfield
    936       811       855       1,043       991       1,085  
Phase 5:
                                               
Delhi
    63       648       511       703       1,524       2,263  
     
Total tertiary oil production
    27,023       28,507       29,531       31,139       30,825       30,771  
     
 
                                               
Tertiary operating expense per Bbl
  $ 22.67     $ 21.37     $ 22.54     $ 22.26     $ 25.40     $ 23.35  
     
     Oil production from our tertiary operations increased to an average of 30,771 Bbls/d during the second quarter of 2011, an 8% increase over our second quarter of 2010 tertiary production level of 28,507 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods in the Tinsley, Heidelberg and Delhi Fields. Offsetting these production gains were declines in our more mature Phase 1 and Phase 2 fields (excluding Heidelberg).
     The production growth rate at a tertiary flood varies from quarter to quarter as a tertiary field’s production may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume its growth as additional areas of the field are developed. During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production. We also find it difficult to precisely predict when any given well will respond to the injected CO2 as the CO2 seldom travels through the rock consistently due to heterogeneity in the oil-bearing formations. We find all these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the entire field is developed, albeit sometimes in inconsistent patterns. These types of fluctuations were most noticeable at Tinsley and Heidelberg Fields in the first quarter of 2011, two of our fields which have exhibited strong production growth in recent periods. These fields resumed their growth during the second quarter of 2011 and these temporary fluctuations have not changed our overall outlook for these fields.
     We initiated CO2 injections at Oyster Bayou and Hastings Fields during June 2010 and December 2010, respectively. We currently anticipate tertiary production responses at Hastings Field in late 2011, assuming our CO2 recycle facilities at this field are completed on schedule. We anticipate first production at Oyster Bayou Field late in the first quarter of 2012, also dependant on the completion of CO2 recycle facilities.
     During the second quarter of 2011, operating costs for our tertiary properties averaged $23.35 per Bbl, down 8% from our first quarter 2011 average of $25.40 per Bbl, due primarily to lower workover expenses between the respective periods, but 9% higher than our second quarter 2010 average cost of $21.37 per Bbl, due primarily to higher utility and CO2 costs. CO2 costs increased due to a 37% increase in injection volumes, primarily related to the ramping up of tertiary activity at our Heidelberg, Tinsley and Delhi fields, and a 27% increase in the cost of CO2 (which is variable and partially tied to oil prices). On a per Bbl basis, our cost of CO2 increased from $5.05 per Bbl during the second quarter of 2010 to $5.62 per Bbl during the second quarter of 2011 but remained relatively consistent with the $5.58 per Bbl level of these costs during the first quarter of 2011. Second quarter of 2011 workover expenses of $2.53 per Bbl also increased from second quarter of 2010 workover expenses of $1.62 per Bbl but decreased from first quarter of 2011 levels of $3.75 per Bbl as we completed planned mechanical integrity test repairs at Brookhaven Field and completed other workovers at Soso and Eucutta during the first quarter of 2011. For any specific field, we expect our tertiary lease operating expense per Bbl to be high initially and then decrease as production increases, ultimately leveling off until production begins to decline in the latter life of the field, when lease operating expense per barrel will again increase.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operating Results
     Certain of our operating results and statistics for the comparative second quarters and first six months of 2011 and 2010 are included in the following table:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands, except per share and unit data   2011     2010(1)     2011     2010(1)  
Operating results:
                               
Net income attributable to Denbury stockholders
  $ 259,246     $ 135,367     $ 245,056     $ 232,255  
Net income per common share — basic
    0.65       0.34       0.62       0.67  
Net income per common share — diluted
    0.64       0.34       0.61       0.66  
Cash flow from operations
    398,521       271,123       523,353       384,291  
Average daily production volumes:
                               
Bbls/d
    59,538       65,942       59,002       55,185  
Mcf/d
    32,283       109,014       31,579       81,108  
BOE/d
    64,919       84,111       64,265       68,703  
Operating revenues:
                               
Oil sales
  $ 575,928     $ 443,984     $ 1,068,766     $ 749,188  
Natural gas sales
    15,171       44,044       28,525       69,726  
 
                       
Total oil and natural gas sales
  $ 591,099     $ 488,028     $ 1,097,291     $ 818,914  
 
                       
Commodity derivative contracts: (2)
                               
Net cash receipts (payments) on settlement of commodity derivative contracts
  $ (10,942 )   $ 2,801     $ (9,354 )   $ (57,000 )
Non-cash fair value adjustment income
    183,846       125,190       11,508       226,029  
 
                       
Total income from commodity derivative contracts
  $ 172,904     $ 127,991     $ 2,154     $ 169,029  
 
                       
Operating expenses:
                               
Lease operating
  $ 129,932     $ 127,743     $ 257,029     $ 223,963  
Production taxes and marketing
    39,688       38,100       72,439       57,417  
 
                       
Total production expenses
  $ 169,620     $ 165,843     $ 329,468     $ 281,380  
 
                       
Unit prices — including impact of derivative settlements: (2)
                               
Oil price per Bbl
  $ 103.17     $ 71.68     $ 98.02     $ 67.26  
Natural gas price per Mcf
    7.22       6.12       7.20       6.14  
Unit prices — excluding impact of derivative settlements: (2)
                               
Oil price per Bbl
  $ 106.30     $ 73.99     $ 100.08     $ 75.00  
Natural gas price per Mcf
    5.16       4.44       4.99       4.75  
Oil and natural gas operating revenues and expenses per BOE:
                               
Oil and natural gas revenues
  $ 100.06     $ 63.76     $ 94.33     $ 65.85  
 
                       
 
                               
Oil and natural gas lease operating expenses
  $ 21.99     $ 16.69     $ 22.10     $ 18.01  
Oil and natural gas production taxes and marketing expense
    6.72       4.98       6.23       4.62  
 
                       
Total oil and natural gas production expenses
  $ 28.71     $ 21.67     $ 28.33     $ 22.63  
 
                       
 
(1)   Includes the results of operations of Encore properties and ENP from March 9, 2010 through the end of the period.
 
(2)   See Item 3, Qualitative and Quantitative Disclosures about Market Risk, for additional information concerning our commodity derivative contracts.

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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 four quarters of 2010 and for the first and second quarters of 2011 are shown below:
                                                         
    Average Daily Production (BOE/d)  
    First     Pro Forma     Second     Third     Fourth     First     Second  
    Quarter     First Quarter     Quarter     Quarter     Quarter     Quarter     Quarter  
Operating Area   2010(1)     2010(2)     2010     2010     2010     2011     2011  
Gulf Coast Region:
                                                       
Tertiary oil fields
    27,023       27,023       28,507       29,531       31,139       30,825       30,771  
Non-tertiary fields:
                                                       
Mississippi
    7,829       7,829       8,967       7,965       7,293       7,586       7,333  
Texas
    5,235       5,235       5,148       4,824       4,564       4,371       4,202  
Louisiana
    662       662       775       714       687       767       659  
Alabama and other
    997       997       1,078       1,091       1,026       1,026       1,084  
 
                                         
Total Gulf Coast Region
    41,746       41,746       44,475       44,125       44,709       44,575       44,049  
 
                                                       
Rocky Mountain Region:
                                                       
Cedar Creek Anticline
    2,537       9,830       9,967       9,791       9,328       9,163       8,925  
Bakken
    890       3,549       4,500       4,657       5,193       5,728       7,626  
Bell Creek
    252       966       997       994       957       890       936  
Paradox
    173       675       702       738       716       635       690  
Other
    777       2,925       2,944       2,889       2,809       2,613       2,693  
 
                                         
Total Rocky Mountain Region
    4,629       17,945       19,110       19,069       19,003       19,029       20,870  
 
                                                       
 
                                         
Total Continuing Production
    46,375       59,691       63,585       63,194       63,712       63,604       64,919  
 
                                         
 
                                                       
Disposed Properties:
                                                       
Legacy Encore properties
    4,479       17,853       11,684       5,906       4,156              
ENP
    2,271       9,034       8,842       8,630       8,567              
 
                                         
 
                                                       
Total Production
    53,125       86,578       84,111       77,730       76,435       63,604       64,919  
 
                                         
 
(1)   Includes production of Encore and ENP from March 9, 2010 through March 31, 2010.
 
(2)   Represents pro forma production assuming we had reported the production from the Encore Merger beginning January 1, 2010.
     Continuing production during the three months ended June 30, 2011 increased 1,334 BOE/d over the comparable 2010 production levels, and continuing production when including Encore’s pre-merger production increased from 61,649 BOE/d during the first half of 2010 to 64,265 BOE/d during the first half of 2011. These increases were primarily due to production increases from the Bakken and our tertiary oil fields (see a discussion of our tertiary operations in CO2 Operations above), offset by normal declines in most of our other non-tertiary properties. Additionally, our production from the Cedar Creek Anticline generally declines in periods of increasing prices due to a net profits interest associated with this production. Total production decreased 23% between the second quarters of 2010 and 2011 due to the sale of non-strategic legacy Encore properties during May 2010 through December 2010, as well as the sale of our interests in ENP in December 2010. On a year-to-date basis, total production decreased 6% between the first six months of 2010 and 2011 due primarily to the sale of the non-strategic Encore assets during 2010.
     Production from our Bakken properties averaged 7,626 BOE/d in the second quarter of 2011, a 69% increase from second quarter 2010 levels and an increase of over 33% compared to first quarter 2011 production levels. The production increases in the Bakken are due to a gradual acceleration of our drilling activities in the area, as we have increased our operated drilling rigs from two, at the time of the Encore acquisition in March 2010, to five operated rigs currently. We anticipate adding a sixth rig late in the third quarter or early fourth quarter of 2011 to test our acreage in the Almond area, and a seventh rig by the end of 2011. During the first six months of 2011, we drilled and completed 16 operated wells in the Bakken. Our Bakken production for the first six months of 2011 was negatively impacted by severe winter weather and flooding which caused delays in well completions and curtailments in oil production.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Our production during both the three and six months ended June 30, 2011 was 92% oil, as compared to 78% and 80%, during the three and six months ended June 30, 2010, respectively. This increase is due to the sales of the non-strategic Encore properties and ENP properties in 2010, which had a higher percentage of natural gas production, and increases in our tertiary and Bakken production, which are primarily oil.
     Oil and Natural Gas Revenues. Although our production for the three and six months ended June 30, 2011 declined from comparable 2010 levels due to the asset sales discussed above (partially offset during the six-month period by lower production in 2010 prior to the Encore Merger which closed in March 2010), our oil and natural gas revenues increased significantly in the current periods due to higher oil prices. These changes in oil and natural gas revenues, excluding any impact of our commodity derivative contracts, are reflected in the following table:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2011 vs. 2010     2011 vs. 2010  
            Percentage             Percentage  
    Increase     Increase             Increase  
    (Decrease) in     (Decrease) in     Increase (Decrease)     (Decrease) in  
In thousands   Revenues     Revenues     in Revenues     Revenues  
Change in oil and natural gas revenues due to:
                               
Increase in commodity prices
  $ 214,398       44 %   $ 331,259       40 %
Decrease in production
    (111,327 )     (23 %)     (52,882 )     (6 %)
 
                       
Total increase in oil and natural gas revenues
  $ 103,071       21 %   $ 278,377       34 %
 
                       
     Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first and second quarters and first six month periods of 2011 and 2010:
                                                 
    Three Months Ended     Three Months Ended     Six Months Ended  
    March 31,     June 30,     June 30,  
    2011     2010     2011     2010     2011     2010  
Net Realized Prices:
                                               
Oil price per Bbl
  $ 93.67     $ 76.53     $ 106.30     $ 73.99     $ 100.08     $ 75.00  
Natural gas price per Mcf
    4.81       5.40       5.16       4.44       4.99       4.75  
Price per BOE
    88.42       69.21       100.06       63.76       94.33       65.85  
 
                                               
NYMEX Differentials:
                                               
Oil per Bbl
  $ (0.59 )   $ (2.08 )   $ 3.72     $ (4.13 )   $ 1.64     $ (3.36 )
Natural gas per Mcf
    0.61       0.37       0.78       0.09       0.70       0.06  
     During the second quarter of 2011, our oil price differentials improved significantly, primarily due to the favorable price differential for crude oil sold under LLS index pricing. Company-wide oil price differentials in the second quarter of 2011 were $3.72 per Bbl above NYMEX, as compared to an average negative differential of $4.13 per Bbl below NYMEX in the second quarter of 2010 and an average negative differential of $0.59 per Bbl during the first quarter of 2011. Our oil price differential in the second quarter of 2010 reflected production from the non-strategic Encore properties sold in 2010, which typically received lower oil prices than our legacy production. During the latter part of the first quarter, the LLS index price increased significantly more than NYMEX prices, causing the LLS differential to increase significantly, and it remained high throughout the second quarter. For the second quarter of 2011, this LLS differential averaged a positive $15.32 per barrel on a trade-month basis, as compared to a $9.28 positive differential in the first quarter of 2011 and a more typical $3.21 positive differential in

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
the second quarter of 2010. It is uncertain how long this LLS differential will remain at this level, Because our derivative contracts are based on NYMEX prices, they do not impact the differential we receive. We currently sell approximately (a) 40% of our crude oil based on the LLS index price, although due to contract provisions we may not realize the full differential; (b) approximately 40% based on WTI prices; and (c) approximately 20% based on various other indexes, most of which also improved relative to WTI, but to a lesser degree.
     Commodity Derivative Contracts. The following tables summarize the impact our commodity derivative contracts had on our operating results for the three and six months ended June 30, 2011 and 2010:
                                                 
    Three Months Ended June 30,  
    2011     2010     2011     2010     2011     2010  
    Oil     Natural Gas        
In thousands   Derivative Contracts     Derivative Contracts     Total Commodity Derivative Contracts  
Non-cash fair value gain (loss)
  $ 187,194     $ 145,099     $ (3,348 )   $ (19,909 )   $ 183,846     $ 125,190  
Cash settlement receipts (payments)
    (16,972 )     (13,829 )     6,030       16,630       (10,942 )     2,801  
 
                                   
Total
  $ 170,222     $ 131,270     $ 2,682     $ (3,279 )   $ 172,904     $ 127,991  
 
                                   
                                                 
    Six Months Ended June 30,  
    2011     2010     2011     2010     2011     2010  
    Oil     Natural Gas        
In thousands   Derivative Contracts     Derivative Contracts     Total Commodity Derivative Contracts  
Non-cash fair value gain (loss)
  $ 20,130       206,920       (8,622 )     19,109     $ 11,508     $ 226,029  
Cash settlement receipts (payments)
    (22,000 )     (77,379 )     12,646       20,379       (9,354 )     (57,000 )
 
                                   
Total
  $ (1,870 )   $ 129,541     $ 4,024     $ 39,488     $ 2,154     $ 169,029  
 
                                   
     Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our commodity derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the changes in fair value of these contracts, as outlined above, are recognized currently in the income statement. See Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
     Production Expenses. Our lease operating expenses increased 2% during the three months ended June 30, 2011 compared to the same period in 2010 primarily as a result of the increased CO2 injections as we continued to ramp up tertiary activities at Tinsley, Heidelberg and Delhi fields during 2010 and 2011, the cost of CO2 (which are variable and partially tied to oil prices) and workover expenses on our tertiary operations (see discussion of those expenses under CO2 Operations), offset by the sale of the non-strategic legacy Encore and ENP properties during 2010.
     The 15% increase in lease operating expense during the six months ended June 30, 2011 compared to 2010 was further impacted by the inclusion in the 2011 period of a full six months of lease operating expense related to properties acquired in the Encore Merger on March 9, 2010.
     Lease operating expense per BOE averaged $21.99 per BOE and $22.10 per BOE for the three and six months ended June 30, 2011, compared to $16.69 per BOE and $18.01 per BOE for the same periods in 2010. These increases from the respective prior periods are attributable to the sale of the non-strategic Encore and ENP properties from May 2010 through December 2010, which generally had a lower operating cost per BOE than Denbury’s legacy properties. However, second quarter 2011 lease operating expenses per BOE decreased from $22.20 per BOE in the first quarter of 2011. Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $23.35 per BOE and $24.37 per BOE during the three and six months ended June 30, 2011, compared to $21.37 per BOE and $22.00 per BOE for the same periods in 2010. See CO2 Operations for a more detailed discussion.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Generally, production taxes change in relation to oil and natural gas revenues, and marketing expenses change in relation to production volumes. The 21% increase in oil and natural gas revenues between the second quarters of 2010 and 2011 contributed to severance taxes increasing from $28.7 to $33.4 million, respectively. Likewise, the 34% increase in oil and natural gas revenues between the first six months of 2010 and 2011 contributed to severance taxes increasing from $43.6 million to $60.9 million, respectively. These severance tax increases in both comparative periods were partially offset by lower marketing expenses primarily attributable to lower production volumes in 2011.
General and Administrative Expenses (“G&A”)
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands, except per BOE data and employees   2011     2010     2011     2010  
Gross cash G&A expense
  $ 60,137     $ 57,909     $ 127,834     $ 106,183  
Gross stock-based compensation
    9,687       7,363       21,024       17,302  
State franchise taxes
    1,668       965       2,827       2,035  
Operator labor and overhead recovery charges
    (31,423 )     (29,086 )     (61,139 )     (51,131 )
Capitalized exploration and development costs
    (9,169 )     (5,959 )     (15,800 )     (10,488 )
 
                       
Net G&A expense
  $ 30,900     $ 31,192     $ 74,746     $ 63,901  
 
                       
G&A per BOE:
                               
Net cash G&A expense
  $ 3.73     $ 3.15     $ 4.78     $ 3.81  
Net stock-based compensation
    1.22       0.79       1.41       1.17  
State franchise taxes
    0.28       0.13       0.24       0.16  
 
                       
Net G&A expense
  $ 5.23     $ 4.07     $ 6.43     $ 5.14  
 
                       
Employees as of June 30
    1,283       1,304       1,283       1,304  
 
                       
     Gross cash G&A expenses increased $2.2 million (4%) and $21.7 million (20%) during the three and six months ended June 30, 2011, respectively, as compared to the same periods of 2010. The increase between the comparative second quarters is reflective of higher salary costs which we consider necessary in order to remain competitive in our industry. The year-to-date comparative increase is primarily impacted by increased expense resulting from the Encore Merger as the 2010 period includes the effect of the Encore Merger beginning on the acquisition date, March 9, 2010. The number of employees at June 30, 2011, compared to June 30, 2010, decreased slightly, by 2%, primarily due to the departure of Encore transition employees who did not accept permanent positions with Denbury and who completed their transition period. However, prior to the Encore Merger, our headcount was 856 employees.
     Additional expense attributable to the legacy Encore office leases and the new Denbury headquarters lease, together with related moving costs, contributed to the higher cash G&A expense during the first six months of 2011. Additionally, stock-based compensation expense increased $2.3 million for the second quarter 2011 when compared to levels in the same period of 2010, due primarily to higher compensation levels.
     Gross cash G&A expenses decreased $7.6 million, or 11% from levels in the first quarter of 2011, due primarily to lower compensation and employee-related costs and lower professional fees in the current quarter. The first quarter of 2011 included higher payroll tax burdens and   401(k) matching contribution associated with bonus payouts, the true-up of long-term incentive compensation estimates, incremental costs associated with relocating our headquarters and higher professional fees associated with year-end work.
     The increase in gross G&A expense during the three and six months ended June 30, 2011, as compared to those costs in the same periods of 2010, was offset in part by an increase in operator overhead recovery charges. Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. As a result of additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year, and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 8% and 20% during the three and six months ended June 30, 2011, as compared to the same periods in 2010. Capitalized exploration and development costs also increased between the periods, primarily due to increased compensation costs subject to capitalization.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The net effect of these changes resulted in a 1% decrease (a 29% increase on a per BOE basis) in G&A expense between the comparable second quarters of 2011 and 2010. Lower production in the most recent quarter attributable to the 2010 sale of properties was the primary factor relating to the higher cost per BOE, as any cost savings as a result of the property sales were offset by other expenses, including compensation increases effective at the beginning of 2011 and incremental expense attributable to the legacy Encore office leases and the new Denbury headquarters noted above.
Interest and Financing Expenses
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands, except per BOE data and interest rates   2011     2010     2011     2010  
Cash interest
  $ 50,509     $ 60,966     $ 104,715     $ 105,940  
Non-cash interest
    4,934       6,367       10,462       9,121  
Less: capitalized interest
    (13,194 )     (23,850 )     (24,151 )     (45,162 )
 
                       
Interest expense, net
  $ 42,249     $ 43,483     $ 91,026     $ 69,899  
 
                       
Interest income and other
  $ 4,955     $ 4,520     $ 8,004     $ 6,390  
Net cash interest expense and other income per BOE (1)
  $ 5.54     $ 4.43     $ 6.31     $ 4.53  
Average debt outstanding
  $ 2,305,104     $ 3,152,564     $ 2,409,284     $ 2,689,894  
Average interest rate (2)
    8.8 %     7.7 %     8.7 %     7.9 %
 
(1)   Cash interest expense less capitalized interest less interest income and other income on a per BOE basis.
 
(2)   Includes commitment fees but excludes debt issue costs and amortization of discount and premium.
     Cash interest expense decreased $10.5 million during the three month period ending June 30, 2011, as compared to the same period in 2010, primarily due to a decrease in our average debt outstanding. Our debt level increased in early 2010 as a result of the Encore Merger and decreased throughout 2010 and in early 2011 as we repaid debt with proceeds from the sale of non-strategic legacy Encore assets and our ENP ownership interest. Year-to-date cash interest expense remained relatively consistent with that incurred in the same period in 2010. The decrease in cash interest expense during both the three and six month comparative periods was offset by lower capitalized interest relating primarily to the Green Pipeline, which was completed and placed into service at the end of June 2010.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands, except per BOE data   2011     2010     2011     2010  
Depletion, depreciation, and amortization (“DD&A”) of oil and natural gas properties
  $ 91,961     $ 116,034     $ 174,047     $ 187,231  
Depletion and depreciation of CO2 assets
    4,588       5,680       9,178       10,980  
Asset retirement obligations
    1,696       1,692       3,259       2,799  
Depreciation of other fixed assets
    5,250       5,803       10,605       10,071  
 
                       
Total DD&A
  $ 103,495     $ 129,209     $ 197,089     $ 211,081  
 
                       
 
                               
DD&A per BOE:
                               
Oil and natural gas properties
  $ 15.85     $ 15.38     $ 15.24     $ 15.28  
CO2 assets and other fixed assets
    1.67       1.50       1.70       1.69  
 
                       
Total DD&A cost per BOE
  $ 17.52     $ 16.88     $ 16.94     $ 16.97  
 
                       
     Depletion of oil and natural gas properties decreased on an absolute dollars basis during the three and six months ended June 30, 2011 as compared to the same periods of 2010, primarily due to the sale of non-strategic legacy Encore assets and our ownership interests in ENP during 2010. Depletion of oil and gas properties increased on a per BOE basis during the second quarter of 2011 compared to 2010, primarily due to higher finding and development costs per barrel associated with the incremental Bakken capital program and upward revisions in estimated future development costs.
     We continually evaluate the performance of our tertiary projects, and if performance indicates that we are reasonably certain of recovering additional reserves from these floods, we recognize those incremental reserves in that quarter. Since we adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change significantly in the future.
     Our DD&A expense for our CO2 assets decreased on an absolute basis for the three and six months ended June 30, 2011 compared to the same periods in 2010 due to proved CO2 reserve increases at Jackson Dome and Riley Ridge at the end of 2010. On a per BOE basis, DD&A expense for our CO2 assets and other fixed assets increased for the three months ended June 30, 2011 compared to those in the prior-year quarter due to decreased oil and natural gas production volumes as a result of the sale of non-strategic Encore properties and our interests in ENP during 2010.
     Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. We did not have a ceiling test write-down at June 30, 2011. However, if oil and natural gas prices were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost pool ceiling test in the future. The possibility and amount of any future write-down is difficult to predict, and will depend upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures, and additional capital spent.
Encore Transaction and Other Costs
     FASC Business Combinations topic requires that all transaction-related costs (advisory, legal, accounting, due diligence, integration, etc.) be expensed as incurred. We recognized transaction and other costs of $2.0 million and $4.4 million for the three and six months ended June 30, 2011, respectively, associated with the Encore Merger, including $1.8 million and $3.6 million, respectively, related to severance costs. Transaction and other costs of $22.8 million and $67.8 million for the three and six months ended June 30, 2010, respectively, included $19.5 million and $20.7 million, respectively, of severance costs, and were significantly higher than 2011 levels. We anticipate that these severance costs will decline in the remainder of 2011 as the integration winds down and fewer former Encore transition employees remain.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
In thousands, except per BOE amounts and tax rates   2011     2010     2011     2010  
Current income tax provision
  $ 12,028     $ 6,941     $ 11,180     $ 7,610  
Deferred income tax provision
    152,528       74,422       144,620       150,694  
 
                       
Total income tax provision
  $ 164,556     $ 81,363     $ 155,800     $ 158,304  
 
                       
Average income tax provision per BOE
  $ 27.85     $ 10.63     $ 13.39     $ 12.73  
Effective tax rate
    38.8 %     35.1 %     38.9 %     38.7 %
     Our income taxes are based on an estimated statutory rate of approximately 38%. Our effective tax rate for the second quarter of 2011 was slightly higher compared to our statutory rate, primarily due to nondeductible expenses. Our effective tax rate for the second quarter of 2010 was lower due to the remeasurement of our deferred tax liabilities as a result of the May 2010 sale of certain legacy Encore properties in the Permian Basin, Mid-continent area and East Texas Basin (the “Southern Assets”), which resulted in an income tax benefit of approximately $3 million recorded in the second quarter of 2010. The nondeductible expenses in 2011 and the income tax benefit recorded in 2010 resulted in a slight increase in the effective tax rate, to 38.9%, during the six months ended June 30, 2011, as compared to 38.7% in the six months ended June 30, 2010. The current income tax expense represents our state income taxes during the three and six months ended June 30, 2011 and 2010.
     As of June 30, 2011, we had an estimated $39.8 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.5 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2011 or future years. The enhanced oil recovery credits do not begin to expire until 2024. Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.
     In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes, and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS subsequently exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. Henceforth, beginning with the 2011 tax year, we are returning to capitalizing and depreciating the costs of these assets for tax purposes. As a result of the prospective nature of the IRS’s determination, there should be no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. However, refund claims of $10.6 million for tax years through 2006 are pending and are pending review by the Joint Committee on Taxation of the U.S. Congress. We are unable to assess the outcome of any such review, nor how that outcome may affect the other years covered by the TAM.
     The President’s 2012 budget, as well as certain Congressional legislative initiatives, have proposed repealing many tax incentives for the oil and gas industry. Those items that would have the most significant impact on us would include the loss of the domestic manufacturing deduction, the repeal of the immediate expensing of intangible drilling costs and tertiary injectant costs, and the elimination of the percentage depletion allowance. It is uncertain whether these or similar tax law changes will be enacted, and if so what the effective date of any such changes might be, although the current proposals would not take effect until 2012. If some or all of these proposals were enacted and included us, they would likely increase the amount of cash taxes that we pay in future periods, and, accordingly, could impact our forecasted capital expenditure budget.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Per BOE Data
     The following table summarizes our cash flow, DD&A, and results of operations on a per BOE basis for the comparative periods. Each of the individual components is discussed above.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
Per BOE data   2011     2010     2011     2010  
Oil and natural gas revenues
  $ 100.06     $ 63.76     $ 94.33     $ 65.85  
Gain (loss) on settlements of derivative contracts
    (1.85 )     0.37       (0.80 )     (4.58 )
Lease operating expenses
    (21.99 )     (16.69 )     (22.10 )     (18.01 )
Production taxes and marketing expenses
    (6.72 )     (4.98 )     (6.23 )     (4.62 )
 
                       
Production netback
    69.50       42.46       65.20       38.64  
Non-tertiary CO2 operating margin
    0.59       0.39       0.53       0.49  
General and administrative expenses
    (5.23 )     (4.07 )     (6.43 )     (5.14 )
Transactions and other costs related to the Encore Merger
    (0.34 )     (2.98 )     (0.38 )     (5.45 )
Net cash interest expense and other income
    (5.54 )     (4.43 )     (6.31 )     (4.53 )
Current income taxes and other
    (0.74 )     0.10       0.28       0.66  
Changes in assets and liabilities relating to operations
    9.22       3.95       (7.90 )     6.23  
 
                       
Cash flow from operations
    67.46       35.42       44.99       30.90  
DD&A
    (17.52 )     (16.88 )     (16.94 )     (16.97 )
Deferred income taxes
    (25.82 )     (9.72 )     (12.43 )     (12.12 )
Gain on sale of interests in Genesis
                      8.17  
Loss on early extinguishment of debt
    (0.06 )           (1.39 )      
Non-cash fair value derivative adjustments
    31.12       16.45       0.99       18.25  
Net income attributable to noncontrolling interest
          1.95             1.47  
Changes in assets and liabilities and other non-cash items
    (11.30 )     (9.53 )     5.85       (11.02 )
 
                       
Net income attributable to Denbury stockholders
  $ 43.88     $ 17.69     $ 21.07     $ 18.68  
 
                       
Critical Accounting Policies
     For additional discussion of our critical accounting policies, 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, 2010.
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, dates of pipeline construction commencement and completion, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, timing of CO2 injections in tertiary flooding projects, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves, potential reserves from tertiary operations, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and natural gas prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our 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 our 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 us or on our behalf. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets; changes in interest rates; general economic conditions; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and natural gas drilling and production activities or which are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

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DENBURY RESOURCES INC.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Long-Term Debt and Interest Rate Sensitivity
     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. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies. The fair value of the subordinated debt is based on quoted market prices. The following table presents the carrying and fair values of our debt, along with average interest rates at June 30, 2011:
                                                                 
                                                    Carrying     Fair  
In thousands, except percentages   2014     2015     2016     2017     2020     2021     Value     Value  
Variable rate debt:
                                                               
Bank Credit Agreement
  $     $     $     $     $     $     $     $  
Fixed rate debt:
                                                               
9.5% Senior Subordinated Notes due 2016
                224,920                         238,142       249,942  
9.75% Senior Subordinated Notes due 2016
                426,350                         406,354       476,446  
8.25% Senior Subordinated Notes due 2020
                            996,273             996,273       1,085,938  
6.375% Senior Subordinated Notes due 2021
                                  400,000       400,000       400,000  
Other Subordinated Notes
    1,072       485             2,250                   3,843       3,807  
Commodity Derivative Contracts and Commodity Price Sensitivity
     From time to time, we enter into oil and natural 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. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for a period generally ranging from approximately 12 to 18 months in advance (although we will hedge farther in advance if deemed prudent), as we believe it is important to protect our future cash flow for a short period of time in order to give us time to adjust to commodity price fluctuations, particularly since many of our expenditures have long lead times. See Note 4, Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
     All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of our commodity derivative contracts are with parties that are lenders under our bank credit agreement. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.
     For accounting purposes, we do not apply hedge accounting to our commodity derivative contracts. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
     At June 30, 2011, our commodity derivative contracts were recorded at their fair value, which was a net liability of approximately $32.5 million (excluding $15.6 million of deferred premiums that Denbury is obligated to pay for its derivative contracts, which payments are not subject to changes in commodity prices), which is less than the $44.0 million fair value liability recorded at December 31, 2010. This change is primarily related to changes in oil futures prices between December 31, 2010 and June 30, 2011.

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DENBURY RESOURCES INC.
     Based on NYMEX crude oil and natural gas futures prices as of June 30, 2011, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil and natural gas derivative contracts as seen in the following table:
                 
    Crude Oil     Natural Gas  
    Derivative     Derivative  
    Contracts     Contracts  
In thousands   (Payment)     Receipt  
Based on:
               
NYMEX futures prices as of June 30, 2011
  $ (9,390 )   $ 24,508  
10% increase in prices
    (81,222 )     18,312  
10% decrease in prices
    (2,952 )     30,703  
Equity Price Sensitivity
     Our investment in Vanguard common units is considered an investment in available-for-sale securities, which is recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. This investment is thus subject to equity price sensitivity, as fair value is determined by quoted market prices. We estimate that a hypothetical 10% increase or decrease in quoted market prices for Vanguard common units would result in a $8.8 million unrealized gain or loss, respectively, as of June 30, 2011.
Item 4. Controls and Procedures
     Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, the Company’s Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011, to ensure: that information required to be disclosed in the reports it files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
     Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the second quarter of fiscal 2011, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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DENBURY RESOURCES INC.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
     Information with respect to this item is incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2010.
Item 1A. Risk Factors
     Information with respect to the risk factors has been incorporated by reference from Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes to the risk factors since the filing of such Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
     The following table summarizes purchases of our common stock during the second quarter of 2011, consisting entirely of delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights:
                                 
                    Total Number of     Approximate Dollar  
    Total             Shares Purchased     Value of Shares  
    Number of     Average     as Part of Publicly     that May Yet Be  
    Shares     Price Paid     Announced Plans or     Purchased Under the  
Month   Purchased     per Share     Programs     Plans or Programs  
April 2011
    17,272     $ 23.97           $  
May 2011
    9,466       21.28              
June 2011
    14,479       19.95              
 
                         
Total
    41,217       21.94           $  
 
                         
Item 6. Exhibits
     
Exhibit   Description
3.1  
Amended and Restated Bylaws of Denbury Resources Inc. effective as of June 17, 2011 (incorporated by reference as Exhibit 3.1 of our Form 8-K filed on June 21, 2011).
   
 
4.1  
Fifth Amendment to Credit Agreement dated as of March 9, 2010, dated as of May 19, 2011, among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference as Exhibit 99.1 of our Form 8-K filed on May 20, 2011).
   
 
31.1*  
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
 
31.2*  
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.
   
 
101*  
Interactive Data Files.
 
*   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.
 
 
  By:   /s/ Mark C. Allen    
    Mark C. Allen   
    Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary   
 
     
  By:   /s/ Alan Rhoades    
    Alan Rhoades   
    Vice President and Chief Accounting Officer   
 
Date: August 8, 2011

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