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DENBURY INC - Quarter Report: 2011 March (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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
(State or other jurisdictions of
incorporation or organization)
  20-0467835
(I.R.S. Employer
Identification No.)
     
5320 Legacy Drive
Plano, TX
(Address of principal executive offices)
  75024
(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   Smaller reporting company    o
             
        (Do not check if a smaller reporting company)    
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 April 29, 2011
     
Common Stock, $.001 par value   401,887,373

 


 

DENBURY RESOURCES INC.
INDEX
         
    Page
PART I. FINANCIAL INFORMATION
       
 
       
Item 1. Financial Statements
       
 
       
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    39  
 
       
    40  
 EX-10.A
 EX-10.B
 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)
                                       
    March 31,   December 31,
 
    2011   2010
ASSETS
 
               
Current assets
               
 
               
Cash and cash equivalents
   $ 127,857      $ 381,869  
 
               
Accrued production receivable
    264,150       223,584  
 
               
Trade and other receivables, net of allowance of $471 and $456, respectively
    138,026       114,149  
 
               
Short-term investments
    99,733       93,020  
 
               
Derivative assets
    19,345       24,242  
 
               
Deferred tax assets
    72,552       27,454  
 
       
 
               
Total current assets
    721,663       864,318  
 
       
 
               
Property and equipment
               
 
               
Oil and natural gas properties (using full cost accounting)
               
 
               
Proved
    6,238,629       6,042,442  
 
               
Unevaluated
    912,267       870,130  
 
               
CO2 and other non-hydrocarbon gases - properties and pipelines
    1,940,392       1,901,662  
 
               
Other property and equipment
    132,692       120,641  
 
               
Less accumulated depletion, depreciation, amortization, and impairment
    (2,295,952 )     (2,197,517 )
 
       
 
               
Net property and equipment
    6,928,028       6,737,358  
 
       
 
               
Derivative assets
    9,203       12,919  
 
               
Goodwill
    1,232,418       1,232,418  
 
               
Other assets
    220,107       218,050  
 
       
 
               
Total assets
   $ 9,111,419      $ 9,065,063  
 
       
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
               
Current liabilities
               
 
               
Accounts payable and accrued liabilities
   $ 246,145      $ 345,998  
 
               
Oil and gas production payable
    161,471       143,145  
 
               
Derivative liabilities
    218,341       78,184  
 
               
Current maturities of long-term debt
    8,446       7,948  
 
               
Other liabilities
    4,070       4,070  
 
       
 
               
Total current liabilities
    638,473       579,345  
 
       
 
               
Long-term liabilities
               
 
               
Long-term debt, net of current portion
    2,344,781       2,416,208  
 
               
Asset retirement obligations
    83,576       81,290  
 
               
Derivative liabilities
    47,745       29,687  
 
               
Deferred taxes
    1,589,912       1,547,992  
 
               
Other liabilities
    25,567       29,834  
 
       
 
               
Total long-term liabilities
    4,091,581       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; 402,155,781 and 400,291,033 shares issued, respectively
    402       400  
 
               
Paid-in capital in excess of par
    3,061,793       3,045,937  
 
               
Retained earnings
    1,321,952       1,336,142  
 
               
Accumulated other comprehensive income (loss)
    3,692       (488 )
 
               
Treasury stock, at cost, 298,707 and 78,524 shares, respectively
    (6,474 )     (1,284 )
 
       
 
               
Total stockholders’ equity
    4,381,365       4,380,707  
 
       
 
               
Total liabilities and stockholders’ equity
   $ 9,111,419      $ 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
 
    March 31,
 
    2011   2010
 
               
Revenues and other income
               
 
               
Oil, natural gas, and related product sales
    $ 506,192     $ 330,886  
 
               
CO2 sales and transportation fees
    4,924       4,497  
 
               
Gain on sale of interests in Genesis
    -       101,568  
 
               
Interest income and other income
    3,049       1,870  
 
       
 
               
Total revenues and other income
    514,165       438,821  
 
       
 
               
Expenses
               
 
               
Lease operating expenses
    127,097       96,220  
 
               
Production taxes and marketing expenses
    32,751       19,317  
 
               
CO2 discovery and operating expenses
    2,154       1,368  
 
               
General and administrative
    43,846       32,709  
 
               
Interest, net of amounts capitalized of $10,957 and $21,312, respectively
    48,777       26,416  
 
               
Depletion, depreciation, and amortization
    93,594       81,872  
 
               
Derivatives expense (income)
    170,750       (41,225 )
 
               
Loss on early extinguishment of debt
    15,783       -  
 
               
Transaction and other costs related to the Encore Merger
    2,359       44,999  
 
       
 
               
Total expenses
    537,111       261,676  
 
       
 
               
Income (loss) before income taxes
    (22,946 )     177,145  
 
               
Income tax provision (benefit)
               
 
               
Current income taxes
    (848 )     669  
 
               
Deferred income taxes
    (7,908 )     76,272  
 
       
 
               
Consolidated net income (loss)
    (14,190 )     100,204  
 
               
Less: net income attributable to noncontrolling interest
    -       (3,316 )
 
       
 
               
Net income (loss) attributable to Denbury stockholders
    $ (14,190 )   $ 96,888  
 
       
 
               
Net income (loss) per common share
               
 
               
Basic
    $ (0.04 )   $ 0.33  
 
               
Diluted
    $ (0.04 )   $ 0.32  
 
               
Weighted average common shares outstanding
               
 
               
Basic
    397,386       294,143  
 
               
Diluted
    397,386       299,224  
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                 
    Three Months Ended
 
    March 31,
 
    2011   2010
 
               
Cash flows from operating activities
               
 
               
Consolidated net income (loss)
  $ (14,190 )    $ 100,204  
 
               
Adjustments needed to reconcile to net cash provided by operating activities
               
 
               
Depletion, depreciation, and amortization
    93,594       81,872  
 
               
Deferred income taxes
    (7,908 )     76,272  
 
               
Gain on sale of interests in Genesis
    -       (101,568 )
 
               
Stock-based compensation
    10,201       7,806  
 
               
Non-cash fair value derivative adjustments
    172,338       (101,026 )
 
               
Loss on early extinguishment of debt
    15,783       -  
 
               
Other, net
    1,399       2,410  
 
               
Changes in operating assets and liabilities:
               
 
               
Accrued production receivable
    (44,243 )     (12,125 )
 
               
Trade and other receivables
    (20,160 )     30,854  
 
               
Other assets
    (5,773 )     (2,775 )
 
               
Accounts payable and accrued liabilities
    (90,382 )     21,971  
 
               
Oil and natural gas production payable
    18,770       13,394  
 
               
Other liabilities
    (4,597 )     (4,121 )
 
       
 
               
Net cash provided by operating activities
    124,832       113,168  
 
       
 
               
Cash flows used for investing activities
               
Oil and natural gas capital expenditures
    (190,296 )     (92,647 )
 
               
Acquisitions of oil and natural gas properties
    (29,801 )     (340 )
 
               
Cash paid in Encore Merger, net of cash acquired
    -       (801,489 )
 
               
CO2 and other non-hydrocarbon gases - capital expenditures, including pipelines
    (66,157 )     (72,647 )
 
               
Deposit received on divesture of Southern Assets
    -       45,000  
 
               
Net proceeds from sale of interests in Genesis
    -       162,622  
 
               
Other
    1,211       (4,826 )
 
       
 
               
Net cash used for investing activities
    (285,043 )     (764,327 )
 
       
 
               
Cash flows from financing activities
               
Bank repayments
    (130,000 )     (625,000 )
 
               
Bank borrowings
    130,000       1,025,000  
 
               
Repayment of senior subordinated notes
    (469,552 )     (508,182 )
 
               
Premium paid on repayment of senior subordinated notes
    (13,137 )     (6,257 )
 
               
Net proceeds from issuance of senior subordinated notes
    400,000       1,000,000  
 
               
Escrowed funds for redemption of senior subordinated notes
    -       (65,566 )
 
               
Costs of debt financing
    (8,441 )     (76,129 )
 
               
Other
    (2,671 )     (4,113 )
 
       
 
               
Net cash provided by (used for) financing activities
    (93,801 )     739,753  
 
       
 
               
Net increase (decrease) in cash and cash equivalents
    (254,012 )     88,594  
 
               
Cash and cash equivalents at beginning of period
    381,869       20,591  
 
       
 
               
Cash and cash equivalents at end of period
   $ 127,857      $ 109,185  
 
       
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
                 
    Three Months Ended  
 
               
    March 31,
 
               
    2011   2010
 
               
Consolidated net income (loss)
    $ (14,190 )     $ 100,204  
 
               
Other comprehensive income (loss), net of income tax:
               
 
               
Net unrealized gains on available-for-sale securities, net of tax of $2,550
    4,163       -  
 
               
Interest rate lock derivative contracts reclassified to income,

net of tax of $11 in each period
    17       17  
 
               
Change in deferred hedge loss on interest rate swaps, net of tax of $10
    -       (27 )
 
       
 
               
Consolidated comprehensive income (loss)
    (10,010 )     100,194  
 
               
Less: comprehensive income attributable to noncontrolling interest
    -       (3,285 )
 
       
 
               
Comprehensive income (loss) attributable to Denbury stockholders
    $ (10,010 )     $ 96,909  
 
       
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 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 March 31, 2011, our consolidated results of operations for the three months ended March 31, 2011 and 2010, and our consolidated cash flows for the three months ended March 31, 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 through 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 have not consolidated ENP in our Unaudited Condensed Consolidated Balance Sheets as of December 31, 2010, nor do our Unaudited Condensed Consolidated Statement of Operations or Cash Flows for the three months ended March 31, 2011 include ENP’s results of operations or cash flows. As presented in the Unaudited Condensed Consolidated Statement of Operations for the three months ended March 31, 2010, “Net income attributable to noncontrolling interest” of $3.3 million 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 months ended March 31, 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  
    March 31,  
 
In thousands   2011     2010  
 
               
Basic weighted average common shares
    397,386       294,143  
Potentially dilutive securities:
               
Stock options and SARs
    -       3,690  
Performance equity awards
    -       477  
Restricted stock
    -       914  
 
       
Diluted weighted average common shares
    397,386       299,224  
 
       
     Basic weighted average common shares excludes 3.5 million shares and 3.4 million shares at March 31, 2011 and 2010, respectively, of unvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant. For purposes of calculating 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  
 
    March 31,  
 
In thousands   2011     2010  
 
               
Stock options and SARs
    12,641        5,465   
Restricted stock
    3,453        1,371   
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 March 31, 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, and under the terms of the sale agreement with Vanguard we are restricted from divesting these Vanguard common units until July 31, 2011. In the first quarter of 2011 we received distributions of $1.8 million on the Vanguard common units we own which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statement of Operations for the three months ended March 31, 2011. The unrealized gain on our short-term investment of $4.2 million, net of taxes of $2.6 million, is included in our Unaudited Condensed Consolidated Statement of Comprehensive Operations for the three months ended March 31, 2011.
Recently Adopted Accounting Pronouncements
     We have reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2011, and have determined that none would have a material impact to our 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.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     For the period from the March 9, 2010 Encore acquisition date to March 31, 2010, we recognized $59.7 million and $43.9 million of oil, natural gas and related product sales and field operating income (oil, natural gas and related product sales less lease operating expenses and production taxes and marketing expenses), respectively, related to the Encore Merger. We recognized a total of $2.4 million and $45.0 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 March 31, 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 preliminary closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase includes 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 includes approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit. We own a non-operating interest in those 28,000 acres.
     The acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. The purchase price allocation for the acquisition of interests in Riley Ridge Field is preliminary and subject to revision pending finalization of closing adjustments. The following table presents a summary of the preliminary fair value of assets acquired:
         
  In thousands    
 
       
Oil and natural gas properties
    $ 19,646  
CO2 and other non-hydrocarbon gases - properties and pipelines (CO2 properties)
    10,907  
CO2 and other non-hydrocarbon gases - properties and pipelines (Riley Ridge plant)
    72,070  
Prepaid construction and drilling costs
    9,346  
Other assets
    19,300  
Asset retirement obligations
    (472 )
Goodwill
    1,460  
 
   
Total
    $ 132,257  
 
   
Pro Forma Information
     Had the Encore Merger and Riley Ridge acquisition both occurred on January 1, 2010, our combined pro forma revenue and net income for the three months ended March 31, 2010, would have been as follows:
                  
In thousands, except per share amounts    
 
       
Pro forma total revenues
    $ 615,271  
Pro forma net income attributable to Denbury stockholders
    112,489  
Pro forma net income per common share:
       
Basic
    $ 0.28  
Diluted
    0.28  
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.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 3. Long-Term Debt
     The following table shows the components of our long-term debt as of the periods indicated:
                                   
    March 31,     December 31,  
 
In thousands   2011     2010  
 
               
Bank Credit Agreement
   $ -      $ -  
 
71/2% Senior Subordinated Notes due 2013, including discount of $96 and $437, respectively (1)
    55,352       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 $13,906 and $14,589, respectively
    238,826       239,509  
 
93/4% Senior Subordinated Notes due 2016, including discount of $21,067 and $22,139, respectively
    405,283       404,211  
 
81/4% Senior Subordinated Notes due 2020
    996,273       996,273  
 
63/8% Senior Subordinated Notes due 2021
    400,000       -  
 
Other Subordinated Notes, including premium of $39 and $41, respectively
    3,845       3,848  
 
NEJD financing
    166,452       167,331  
 
Free State financing
    80,979       81,188  
 
Capital lease obligations
    6,217       6,806  
 
       
 
Total
    2,353,227       2,424,156  
 
Less current obligations
    8,446       7,948  
 
       
 
Long-term debt and capital lease obligations
   $ 2,344,781      $ 2,416,208  
 
       
 
     
(1)  
These notes were repurchased on April 1, 2011.
Bank Credit Agreement
     On March 9, 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and 23 other lenders as party thereto (the “Bank Credit Agreement”) with a maturity date of March 2014. Availability under the Bank Credit Agreement is subject to a borrowing base (currently $1.6 billion) which is re-determined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. We expect our semi-annual redetermination to be finalized in mid-May 2011. We currently do not anticipate any reduction in our borrowing base as a result of this redetermination.
     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. We incur a commitment fee of 0.5% on the unused portion of the credit facility or if less, the borrowing base. Loans under the Bank Credit Agreement mature in March 2014. We had no borrowings outstanding on the Bank Credit Agreement as of March 31, 2011.
63/8% Senior Subordinated Notes due 2021
     In February 2011, we issued $400 million of 63/8% 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 approximately $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).

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     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% after August 15, 2016; 102.125% after August 15, 2017; 101.062% after August 15, 2018; and 100% 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 $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. By March 3, 2011, upon expiration of the tender offers, 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 for 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 repurchasing all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. During the first quarter of 2011, we recognized a $15.8 million loss associated with the first quarter of 2011 debt repurchases, which is included in our income statement 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.
     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.
     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.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     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
 
    March 31,
  In thousands   2011   2010
Oil
               
Payment on settlements of derivative contracts
  $ 5,028     $ 63,550  
Fair value adjustments to derivative contracts - expense (income)
    167,064       (61,821 )
 
           
Total derivative expense - oil
    172,092       1,729  
Natural Gas
               
Receipt on settlements of derivative contracts
    (6,616 )     (3,749 )
Fair value adjustments to derivative contracts - expense (income)
    5,274       (39,018 )
 
           
Total derivative income - natural gas
    (1,342 )     (42,767 )
Ineffectiveness on interest rate swaps
    -       (187 )
 
           
Derivative expense (income)
  $ 170,750     $ (41,225 )
 
           

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments
     The following tables present the fair value of our commodity derivative contracts:
                                                         
                                            Estimated Fair Value
 
   
                    NYMEX Contract Prices Per Bbl   Asset (Liability)
 
   
        Type of           Weighted Average Price   March 31,   December 31,
 
   
Year   Months   Contract   Bbls/d   Swap   Floor   Ceiling   2011   2010
                                            (In thousands)
Oil Contracts:
                                                       
2011
  Jan - Mar   Swap     625     $ 79.18     $ -     $ -     $ -     $ (737 )
 
      Collar     43,500       -       67.25       95.80       -       (3,656 )
 
      Put     6,625       -       69.53       -       -       79  
 
                                                 
Total Jan - Mar 2011
    50,750                               -       (4,314 )
 
                                                 
 
                                                       
 
  Apr - June   Swap     625       79.18       -       -       (1,593 )     (827 )
 
      Collar     43,500       -       70.34       100.20       (34,918 )     (12,113 )
 
      Put     6,625       -       69.53       -       16       499  
 
                                                 
Total Apr - June 2011
    50,750                               (36,495 )     (12,441 )
 
                                                 
 
                                                       
 
  July - Sept   Swap     625       79.18       -       -       (1,656 )     (865 )
 
      Collar     42,500       -       70.35       100.09       (48,434 )     (17,308 )
 
      Put     6,625       -       69.53       -       170       1,026  
 
                                                 
Total July - Sept 2011
    49,750                               (49,920 )     (17,147 )
 
                                                 
 
                                                       
 
  Oct - Dec   Swap     625       79.18       -       -       (1,658 )     (871 )
 
      Collar     45,500       -       70.33       101.74       (53,941 )     (18,878 )
 
      Put     6,625       -       69.53       -       477       1,445  
 
                                                 
Total Oct - Dec 2011
    52,750                               (55,122 )     (18,304 )
 
                                                 
 
                                                       
2012
  Jan - Mar   Swap     625       81.04       -       -       (1,502 )     (741 )
 
      Collar     52,000       -       70.00       106.86       (55,070 )     (19,065 )
 
      Put     625       -       65.00       -       51       123  
 
                                                 
Total Jan - Mar 2012
    53,250                               (56,521 )     (19,683 )
 
                                                 
 
                                                       
 
  Apr-June   Swap     625       81.04       -       -       (1,450 )     (726 )
 
      Collar     53,000       -       70.00       119.44       (29,230 )     (3,288 )
 
      Put     625       -       65.00       -       78       151  
 
                                                 
Total Apr - June 2012
    54,250                               (30,602 )     (3,863 )
 
                                                 
 
                                                       
 
  July-Sept   Swap     625       81.04       -       -       (1,402 )     (719 )
 
      Collar     48,000       -       80.00       127.70       (6,663 )     -  
 
      Put     625       -       65.00       -       103       178  
 
                                                 
Total July - Sept 2012
    49,250                               (7,962 )     (541 )
 
                                                 
 
                                                       
 
  Oct - Dec   Swap     625       81.04       -       -       (1,356 )     (709 )
 
      Collar     48,000       -       80.00       127.70       (6,014 )     -  
 
      Put     625       -       65.00       -       117       191  
 
                                                 
Total Oct - Dec 2012
    49,250                               (7,253 )     (518 )
 
                                                 
 
                                                       
 
                                                   
Total Oil Contracts
  $ (243,875 )   $ (76,811 )
 
                                                   

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
                                                         
                                            Estimated Fair Value
 
   
                    Contract Prices Per MMBtu   Asset (Liability)
 
   
        Type of           Weighted Average Price   March 31,   December 31,
 
   
Year   Months   Contract   MMBtu/d   Swap   Floor   Ceiling   2011   2010
                                            (In thousands)
Natural Gas Contracts:
                                                 
2011
  Jan - Mar   Swap     33,500     $ 6.27     $ -     $ -     $ -     $ 5,846  
 
                                                 
Total Jan-Mar 2011
    33,500                               -       5,846  
 
                                                 
 
                                                       
 
  Apr-Jun   Swap     33,500       6.27       -       -       5,841       5,637  
 
                                                 
Total Apr-June 2011
    33,500                               5,841       5,637  
 
                                                 
 
                                                       
 
  July - Sept   Swap     33,500       6.27       -       -       5,327       5,300  
 
                                                 
Total July-Sept 2011
    33,500                               5,327       5,300  
 
                                                 
 
                                                       
 
  Oct - Dec   Swap     33,500       6.27       -       -       4,615       4,409  
 
                                                 
Total Oct - Dec 2011
    33,500                               4,615       4,409  
 
                                                 
 
                                                       
2012
  Jan - Dec   Swap     20,000       6.53       -       -       11,753       11,618  
 
                                                 
Total Jan - Dec 2012
    20,000                               11,753       11,618  
 
                                                 
Total Natural Gas Contracts
    27,536       32,810  
 
                                                   
 
                                                       
Total Commodity Derivative Contracts
  $ (216,339 )   $ (44,001 )
 
                                                   
 
                                                       
     As of March 31, 2011 and December 31, 2010, we had $21.2 million and $26.7 million, respectively, of deferred premiums payable, which relate to various oil and natural gas floor contracts and are payable on a monthly basis from April 2011 to January 2013. These premiums are excluded from the above tables.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Additional Disclosures about Derivative Instruments
     At March 31, 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)
        March 31, 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   $ 714    $   3,050   
Natural gas contracts
  Derivative assets - current     18,631        21,192   
Oil contracts
  Derivative assets - long-term     298        1,301   
Natural gas contracts
  Derivative assets - long-term     8,905        11,618   
 
                   
Derivative liability:
                   
Oil contracts
  Derivative liabilities - current     (198,772)     (55,256)
Deferred premiums
  Derivative liabilities - current     (19,569)     (22,928)
Oil contracts
  Derivative liabilities - long-term     (46,115)     (25,906)
Deferred premiums
  Derivative liabilities - long-term     (1,630)     (3,781)
 
               
Total derivatives not designated as hedging instruments
      $ (237,538) $   (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:
   
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 (i.e., Houston Ship Channel).

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
     We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and Denbury’s credit quality for liability positions. Denbury uses 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  
March 31, 2011
                               
Assets:
                               
Short-term investments
  $ 99,733      $     $     $ 99,733   
Oil and natural gas derivative contracts
          13,202        15,346        28,548   
Liabilities:
                               
Oil and natural gas derivative contracts
          (244,887)           (244,887)
 
                       
Total
  $ 99,733      $ (231,685)   $ 15,346      $ (116,606)
 
                       
 
                               
December 31, 2010
                               
Assets:
                               
Short-term investments
  $ 93,020      $     $     $ 93,020   
Oil 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 and liabilities for the three months ended March 31, 2011 and 2010:
                 
    Fair Value Measurements Using Significant  
 
   
    Unobservable Inputs (Level 3)  
 
    Three Months Ended     Three Months Ended  
 
   
In thousands   March 31, 2011     March 31, 2010  
Balance, beginning of period
  $ 16,478      $  
Unrealized gains on commodity derivative contracts included in earnings
    310        14,773   
Commodity derivative contracts acquired from Encore
          38,093   
Receipts on settlement of commodity derivative contracts
    (1,442)     (2,348)
 
           
Balance, end of period
  $ 15,346      $ 50,518   
 
           
     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 expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
     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:
                                 
    March 31, 2011     December 31, 2010  
    Carrying     Estimated     Carrying     Estimated  
In thousands, except percentages   Amount     Fair Value     Amount     Fair Value  
 
                               
71/2% Senior Subordinated Notes due 2013 (1)
  $ 55,352     $ 55,448     $ 224,563     $ 228,375  
71/2% Senior Subordinated Notes due 2015
    -       -       300,427       310,500  
91/2% Senior Subordinated Notes due 2016
    238,826       253,597       239,509       249,661  
93/4% Senior Subordinated Notes due 2016
    405,283       480,710       404,211       475,380  
81/4% Senior Subordinated Notes due 2020
    996,273       1,113,335       996,273       1,080,956  
63/8% Senior Subordinated Notes due 2021
    400,000       410,000       -       -  
 
                               
                                 
 
   
(1) These notes were repurchased on April 1, 2011.
                               
     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, 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:
                 
    March 31,     December 31,  
In thousands   2011     2010  
Accounts payable
  $ 53,754      $ 47,660   
Accrued exploration and development costs
    75,967        101,758   
Accrued compensation
    17,820        39,757   
Accrued interest
    31,405        57,077   
Taxes payable
    7,198        34,371   
Other
    60,001        65,375   
 
           
Total
  $ 246,145      $ 345,998   
 
           
Supplemental Cash Flow Information
     The following table sets forth supplemental cash flow information for the periods indicated:
                 
    As of  
    March 31,  
In thousands   2011     2010  
Cash paid for interest, net of amounts capitalized
  $ 66,172      $ 21,962   
Interest capitalized
    10,957        21,312   
Cash paid for income taxes
    19,933        8,030   
Cash received for income tax refunds
    222        12,625   
Increase (decrease) in accrued liabilities for capital expenditures
    (12,503)     32,399   
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. 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 from an undisclosed source in the Gulf Coast region. These contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these 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 late 2014 or early 2015, 115 MMcf/d of CO2 from the IGCC project by 2014 and 50 MMcf/d of CO2 from a Gulf Coast region source 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. These CO2 purchase agreements are contingent on completion or modification of the respective plants by their operators.
     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 impact on the Company.
     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.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 8. Condensed Consolidating Financial Information
     Denbury’s subordinated debt is fully and unconditionally guaranteed jointly and severally by certain of its subsidiaries, except that with respect to Denbury’s $55 million of 7½% Senior Subordinated Notes due 2013 that remained outstanding at March 31, 2011, Denbury Resources Inc. and Denbury Onshore, LLC were co-obligors at March 31, 2011. These 7½% Notes have since been redeemed and are no longer outstanding. Except as noted in the first sentence of this paragraph, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. In the case of the 6¼% Notes, the 6% Notes, the 7¼% Notes and the 9½% Notes previously issued by Encore, Denbury is the sole issuer by virtue of the fact that it is the successor in interest to Encore with respect to all such notes. Each subsidiary guarantor and the subsidiary that was a co-obligor are wholly-owned, directly or indirectly, by Denbury Resources Inc.
     All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between Denbury Resources Inc., Denbury Onshore, LLC, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with Denbury Resources Inc. and then eliminated to arrive at consolidated totals per the accompanying Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Balance Sheets
                                                 
    March 31, 2011  
    Denbury     Denbury                            
 
    Resources Inc.     Onshore, LLC                            
 
    (Parent and     (Issuer and     Guarantor     Non-Guarantor             Consolidated  
 
In thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Subsidiaries     Eliminations     Total  
ASSETS
                                               
Current assets:
                                               
Cash and cash equivalents
   $ 3,947       $ 119,569       $ 3,630       $ 711       $      $ 127,857   
Other current assets
    476,986        559,354        461,605              (904,139)        593,806   
 
                                   
Total current assets
    480,933        678,923        465,235        711        (904,139)        721,663   
 
                                   
 
                                               
Property and equipment:
                                               
Oil and natural gas properties (using full cost accounting):
                                             
Proved
          6,238,629                          6,238,629   
Unevaluated
          912,267                          912,267   
CO2 and other non-hydrocarbon gases - properties and pipelines
          707,008        1,223,900        9,484              1,940,392   
Other property and equipment
          128,421        4,271                    132,692   
Less accumulated depletion, depreciation, amortization, and impairment
          (2,267,862)        (28,090)                    (2,295,952)  
 
                                   
Net property and equipment
          5,718,463        1,200,081        9,484              6,928,028   
 
                                   
 
                                               
Derivative assets
          9,203                          9,203   
Goodwill
    1,061,123        171,295                          1,232,418   
Other assets
    549,334        144,456              33        (473,723)        220,107   
Investment in subsidiaries (equity method)
    4,354,965        2,666        4,369,801              (8,727,432)         
 
                                   
Total assets
   $ 6,446,355       $ 6,725,006       $ 6,035,124       $ 10,228      $ (10,105,294)       $ 9,111,419   
 
                                   
 
                                               
LIABILITIES AND EQUITY
                                               
Current liabilities
   $ 20,764       $ 901,331       $ 609,794       $ 10,723      $ (904,139)       $ 638,473   
Long-term debt, net of current portion
    2,044,226        726,905                    (426,350)        2,344,781   
Asset retirement obligations
          83,576                          83,576   
Derivative liabilities
          47,745                          47,745   
Deferred taxes
          569,597        1,067,688              (47,373)        1,589,912   
Other liabilities
          22,890        2,677                    25,567   
 
                                   
Total liabilities
    2,064,990        2,352,044        1,680,159        10,723        (1,377,862)        4,730,054   
Total equity
    4,381,365        4,372,962        4,354,965        (495)        (8,727,432)        4,381,365   
 
                                   
Total liabilities and equity
   $ 6,446,355       $ 6,725,006       $ 6,035,124       $ 10,228      $ (10,105,294)       $ 9,111,419   
 
                                   

 
                                               
    December 31, 2010  
    Denbury     Denbury                            
 
    Resources Inc.     Onshore, LLC                            
 
    (Parent and     (Issuer and     Guarantor     Non-Guarantor             Consolidated  
 
In thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Subsidiaries     Eliminations     Total  
ASSETS
                                               
Current assets:
                                               
Cash and cash equivalents
   $ 457       $ 380,273       $ 1,139       $      $      $ 381,869   
Other current assets
    144,247        487,942        449,871              (599,611)        482,449   
 
                                   
Total current assets
    144,704        868,215        451,010              (599,611)        864,318   
 
                                   
 
                                               
Property and equipment:
                                               
Oil and natural gas properties (using full cost accounting):
                                             
Proved
          6,042,442                          6,042,442   
Unevaluated
          870,130                          870,130   
CO2 and other non-hydrocarbon gases - properties and pipelines
          681,963        1,216,841        2,858              1,901,662   
Other property and equipment
          116,370        4,271                    120,641   
Less accumulated depletion, depreciation, amortization and impairment
          (2,177,040)        (20,477)                    (2,197,517)  
 
                                   
Net property and equipment
          5,533,865        1,200,635        2,858              6,737,358   
 
                                   
 
                                               
Derivative assets
          12,919                          12,919   
Goodwill
    1,061,123        171,295                          1,232,418   
Other assets
    830,454        144,333                    (756,744)        218,050   
Investment in subsidiaries (equity method)
    4,332,347        2,666        4,357,128              (8,692,141)         
 
                                   
Total assets
   $ 6,368,628       $ 6,733,293       $ 6,008,780       $ 2,858       $ (10,048,496)       $ 9,065,063   
 
                                   
 
                                               
LIABILITIES AND EQUITY
                                               
Current liabilities
   $ 43,654        517,686        614,388        3,228        (599,611)        579,345   
Long-term debt, net of current portion
    1,944,267        1,198,291                    (726,350)        2,416,208   
Asset retirement obligations
          81,290                          81,290   
Derivative liabilities
          29,687                          29,687   
Deferred taxes
          516,319        1,062,045        22        (30,394)        1,547,992   
Other liabilities
          29,834                          29,834   
 
                                   
Total liabilities
    1,987,921        2,373,107        1,676,433        3,250        (1,356,355)        4,684,356   
Total equity
    4,380,707        4,360,186        4,332,347        (392)        (8,692,141)        4,380,707   
 
                                   
Total liabilities and equity
   $ 6,368,628       $ 6,733,293       $ 6,008,780       $ 2,858       $ (10,048,496)       $ 9,065,063   
 
                                   

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Operations
                                                 
    Three Months Ended March 31, 2011  
    Denbury     Denbury                            
 
   
    Resources Inc.     Onshore, LLC                            
 
   
    (Parent and     (Issuer and     Guarantor     Non-Guarantor             Consolidated  
 
   
In thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Subsidiaries     Eliminations     Total  
 
                                               
Revenues and other income:
                                               
Oil, natural gas, and related product sales
   $      $ 506,192       $      $      $      $ 506,192   
CO2 sales and transportation fees
          3,733        22,217              (21,026)        4,924   
Interest income and other
    32,433        3,047        8,594              (41,025)        3,049   
 
                                   
Total revenues
    32,433        512,972        30,811              (62,051)        514,165   
 
                                   
Expenses:
                                               
Lease operating expenses
          145,846                    (18,749)        127,097   
Production taxes and marketing expenses
          32,751                          32,751   
CO2 discovery and operating expenses
          1,809        2,622              (2,277)        2,154   
General and administrative
    191        42,553        945        157              43,846   
Interest, net of amounts capitalized
    50,321        12,647        (301)              (13,890)        48,777   
Depletion, depreciation, and amortization
          92,212        1,382                    93,594   
Derivatives expense
          170,750                          170,750   
Loaa on early extinguishment of debt
    13,670        2,113                          15,783   
Transaction costs and other related to the Encore Merger
          123        2,236                    2,359   
 
                                   
Total expenses
    64,182        500,804        6,884        157        (34,916)        537,111   
 
                                   
Income (loss) before income taxes
    (31,749)        12,168        23,927        (157)        (27,135)        (22,946)  
Income tax provision (benefit)
    (17,661)        3,574        5,386        (55)              (8,756)  
 
                                   
Consolidated net income (loss)
  $ (14,088)      $ 8,594      $ 18,541      $ (102)      $ (27,135)      $ (14,190)  
 
                                   

 
                                               
    Three Months Ended March 31, 2010  
    Denbury     Denbury                            
 
   
    Resources Inc.     Onshore, LLC                            
 
   
    (Parent and     (Issuer and     Guarantor     Non-Guarantor             Consolidated  
 
   
In thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Subsidiaries     Eliminations     Total  
 
                                               
Revenues and other income:
                                               
Oil, natural gas, and related product sales
   $      $ 270,571       $ 47,881       $ 12,434       $      $ 330,886   
CO2 sales and transportation fees
          4,497                          4,497   
Gain on sale of interests in Genesis
          (160)        101,728                      101,568   
Interest income and other
    127,106        827        (7,446)              (118,621)        1,870   
 
                                   
Total revenues
    127,106        275,735        142,163        12,438        (118,621)        438,821   
 
                                   
Expenses:
                                               
Lease operating expenses
          85,884        7,552        2,784              96,220   
Production taxes and marketing expenses
          12,277        5,653        1,387              19,317   
CO2 discovery and operating expenses
          1,360                          1,368   
General and administrative
    118        26,683        5,227        681              32,709   
Interest, net of amounts capitalized
    33,828        13,944        (6,418)        1,079        (16,017)        26,416   
Depletion, depreciation, and amortization
          65,025        13,748        3,099              81,872   
Derivatives income
          (31,638)        (5,817)        (3,770)              (41,225)  
Transaction costs and other related to the Encore Merger
            43,809        252        938              44,999   
 
                                   
Total expenses
    33,946        217,344        20,205        6,198        (16,017)        261,676   
 
                                   
Income before income taxes
    93,160        58,391        121,958        6,240        (102,604)        177,145   
Income tax provision (benefit)
    (7,044)        66,871        17,101        13              76,941   
 
                                   
Consolidated net income (loss)
    100,204        (8,480)        104,857        6,227        (102,604)        100,204   
 
                                   
Less: net income attributable to noncontrolling interest
                      (3,316)              (3,316)  
 
                                   
Consolidated net income (loss) attributable to Denbury stockholders
  $ 100,204      $ (8,480)      $ 104,857      $ 2,911      $ (102,604)      $ 96,888   
 
                                   

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DENBURY RESOURCES INC.
Notes to Unaudited Condensed Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
                                                 
    Three Months Ended March 31, 2011  
    Denbury     Denbury                            
 
   
    Resources Inc.     Onshore, LLC                            
 
   
    (Parent and     (Issuer and     Guarantor     Non-Guarantor             Consolidated  
 
   
In thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Subsidiaries     Eliminations     Total  
 
                                               
Cash flow from operating activities:
                                               
Net cash provided by (used for) operating activities
  $ (74,995)       $ 476,567       $ 30,785       $ 5,549      $ (313,074)       $ 124,832   
 
                                   
Cash flow used for investing activities:
                                               
Oil and natural gas capital expenditures
          (190,296)                          (190,296)  
Acquisitions of oil and natural gas properties
          (29,801)                          (29,801)  
CO2 and other non-hydrocarbon gases - capital expenditures, including pipelines
          (33,025)        (28,294)        (4,838)              (66,157)  
Other
          1,211                          1,211   
 
                                   
Net cash used for investing activities
          (251,911)        (28,294)        (4,838)              (285,043)  
 
                                   
Cash flow from financing activities:
                                               
Bank repayments
    (130,000)                                (130,000)  
Bank borrowings
    130,000                                130,000   
Repayment of senior subordinated notes
    (300,000)        (469,552)                    300,000        (469,552)  
Premium paid on repayment of senior subordinated notes
    (12,078)        (13,137)                    12,078        (13,137)  
Net proceeds from issuance of senior subordinated debt
    400,000                                400,000   
Costs of debt financing
    (8,441)                                (8,441)  
Other
    (996)        (2,671)                    996        (2,671)  
 
                                   
Net cash provided by (used for) financing activities
    78,485        (485,360)                    313,074        (93,801)  
 
                                   
Net increase (decrease) in cash and cash equivalents
    3,490        (260,704)        2,491        711              (254,012)  
Cash and cash equivalents at beginning of period
    457        380,273        1,139                    381,869   
 
                                   
Cash and cash equivalents at end of period
   $ 3,947       $ 119,569       $ 3,630       $ 711       $      $ 127,857   
 
                                   

 
                                               
    Three Months Ended March 31, 2010  
    Denbury     Denbury                            
 
   
    Resources Inc.     Onshore, LLC                            
 
   
    (Parent and     (Issuer and     Guarantor     Non-Guarantor             Consolidated  
 
   
In thousands   Co-Obligor)     Co-Obligor)     Subsidiaries     Subsidiaries     Eliminations     Total  
 
                                               
Cash flow from operating activities:
                                               
Net cash provided by operating activities
   $ 3,173       $ 219,573       $ 190,852       $ 6,882      $ (307,312)       $ 113,168   
 
                                   
Cash flow used for investing activities:
                                               
Oil and natural gas capital expenditures
          (70,061)        (22,262)        (324)              (92,647)  
Acquisitions of oil and natural gas properties
          (503)        455        (292)              (340)  
Cash paid in Encore Merger, net of cash acquired
    (830,310)              15,705        13,116              (801,489)  
CO2 and other non-hydrocarbon gases - capital expenditures, including pipelines
          (37,011)        (35,636)                    (72,647)  
Deposit received on divesture of Southern Assets
    45,000                                45,000   
Net proceeds from sales of oil and gas properties and equipment
          23,537        139,085                    162,622   
Investments in subsidiaries (equity method)
    (305,646)                          305,646         
Other
          (4,799)        (27)                    (4,826)  
 
                                   
Net cash provided by (used for) investing activities
    (1,090,956)        (88,837)        97,320        12,500        305,646        (764,327)  
 
                                   
Cash flow from financing activities:
                                               
Bank repayments
          (350,000)        (265,000)        (10,000)              (625,000)  
Bank borrowings
    800,000        225,000                          1,025,000   
Repayment of senior subordinated notes
    (508,182)                                (508,182)  
Premium paid on repayment of senior subordinated notes
    (6,257)                                        (6,257)  
Net proceeds from issuance of senior subordinated debt
    1,000,000                                1,000,000   
Escrowed Funds for senior subordinated notes redemption
    (65,566)                                (65,566)  
Costs of debt financing
    (76,129)                                (76,129)  
Other
    (1,666)        (2,139)        (1,974)              1,666        (4,113)  
 
                                   
Net cash provided by (used for) financing activities
    1,142,200        (127,139)        (266,974)        (10,000)        1,666        739,753   
 
                                   
Net increase in cash and cash equivalents
    54,417        3,597        21,198        9,382              88,594   
Cash and cash equivalents at beginning of period
    24        20,281        286                    20,591   
 
                                   
Cash and cash equivalents at end of period
   $ 54,441       $ 23,878       $ 21,484       $ 9,382       $      $ 109,185   
 
                                   
Note 9. Subsequent Events
Redemption of our 2013 Notes
     On February 3, 2011, we commenced cash tender offers to purchase $225 million principal amount of our 2013 Notes. By March 3, 2011, upon expiration of the tender offers, we accepted for purchase $169.6 million in principal amount of the 2013 Notes at 100.625% of par. On April 1, 2011, we repurchased all $55.4 million of our 2013 Notes remaining outstanding at par in accordance with the terms of our indenture. See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for more information.

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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.
     Operating Highlights. 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 first quarter 2010 financial results to those in the first quarter of 2011, which is more fully discussed throughout the following discussion and analysis. Our first quarter 2010 financial results include the results of operations for Encore from the date of the acquisition on March 9, 2010 through March 31, 2010. Additionally, throughout 2010 we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).
     We recognized a net loss of $14.2 million, or $0.04 per basic common share, during the first quarter of 2011 as compared to net income of $96.9 million, or $0.33 per basic common share, during the first quarter of 2010. This decrease between the two periods is primarily attributable to (1) non-cash fair value losses for our commodity derivatives of $172.3 million in the first quarter of 2011 compared to gains of $100.8 million in 2010, resulting in a $273.1 million negative change between the comparable quarters ($169.3 million after tax), (2) a $101.6 million gain on the sale of Genesis in the first quarter of 2010 ($63.0 million after tax), and (3) a $15.8 million loss in the first quarter of 2011 associated with repurchases of senior subordinated notes ($9.8 million after tax). Partially offsetting these decreases was an increase in oil and gas revenues of $175.3 million due to increased volumes attributable to a full quarter of production from the properties retained from the Encore Merger (versus 22 days of production in the first quarter of 2010), increased tertiary production, and higher oil prices. In-line with higher production volumes, our operating expenses increased across the board. Interest expense also increased significantly due to our additional debt incurred in conjunction with the Encore Merger.
     During the first quarter of 2011, our oil and natural gas production averaged 63,604 BOE/d compared to 53,125 BOE/d produced during the first quarter of 2010. This 10,479 BOE/d of additional production is primarily attributable to (1) incremental average production of 14,400 BOE/d from Rocky Mountain region properties acquired in the Encore Merger, and (2) increased tertiary production between the two quarters, offset by (3) a decrease of 6,750 BOE/d due to the sales of non-strategic Encore assets and our interests in ENP after the first quarter of 2010. See Results of Operations — Operating Results — Production for more information.
     Tertiary oil production averaged 30,825 Bbls/d during the first quarter of 2011, representing a 14% increase over our average tertiary oil production of 27,023 Bbls/d during the first quarter of 2010. However, tertiary oil production was down slightly from the 31,139 Bbls/d produced during the fourth quarter of 2010. See Results of Operations — CO2 Operations for more information.
     Oil prices during the first quarter of 2011 were considerably higher than prices during the first quarter of 2010. Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $88.42 per BOE during the first quarter of 2011, compared to $69.21 per BOE during the first quarter of 2010, a 28% 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 $88.70 per BOE during the first quarter of 2011 compared to $56.70 per BOE during the first quarter of 2010.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Debt Refinancing. In February 2011, we issued, at par, $400 million of 63/8% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to repurchase $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes. Also, in February, we commenced cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes. Upon expiration of the tender offers in March 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, repurchased all of the remaining outstanding 2015 Notes at 103.75% of par on March 21, 2011 and repurchased all of the remaining outstanding 2013 Notes at par on April 1, 2011. During the first quarter of 2011, we recognized a $15.8 million loss associated with the debt repurchases, included in our income statement under the caption “Loss on early extinguishment of debt”.
     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. 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 from an undisclosed source in the Gulf Coast region. We estimate that these 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 late 2014 or early 2015, 115 MMcf/d of CO2 from the IGCC project by 2014, and 50 MMcf/d of CO2 from a Gulf Coast region source 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. These CO2 purchase agreements are contingent on completion or modification of the respective plants by their operators.
Capital Resources and Liquidity
     In March 2011, commensurate with higher oil prices, our Board of Directors approved an increase in our 2011 capital spending budget, from $1.1 billion to $1.3 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;
 
   
$150 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.
     This estimate also assumes that we fund approximately $60 million of budgeted equipment purchases with operating leases, which is dependent upon securing acceptable financing. 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.
     Based on oil and natural gas commodity futures prices in early May 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is $100 million to $200 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 which currently has no outstanding borrowings.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     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 reduce our anticipated production levels in future years. For 2011, we have contracted for certain capital expenditures, including construction of the Greencore pipeline, processing facilities at Riley Ridge, and several drilling rigs, and therefore we cannot eliminate all of our capital commitments 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 for further information regarding these commitments). See CO2 Purchase Contracts above and Off-Balance Sheet Arrangements below for further information regarding additional commitments entered into in 2011. We believe that our $1.6 billion Bank Credit Agreement and oil derivative contracts, which provide a $70 floor price through mid-2012 and an $80 floor price for the second half of 2012 on approximately 80%-85% of our currently anticipated proved oil production, provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly.
     Capital Expenditure Summary. The following table of capital expenditures includes accrued capital for the three month periods of 2011 and 2010.
                 
    Three Months Ended  
    March 31,  
In thousands   2011     2010  
Oil and natural gas exploration and development:
               
Drilling
   $ 91,732       $ 48,261   
Geological, geophysical, and acreage
    6,666        6,994   
Facilities
    51,814        37,710   
Recompletions
    47,402        28,536   
Capitalized interest
    7,700        5,743   
 
           
Total oil and natural gas exploration and development expenditures
    205,314        127,244   
CO2 and other non-hydrocarbon gases - capital expenditures:
               
Pipelines and facilities
    24,737        42,973   
Acreage, geological and drilling
    10,615        11,907   
Capitalized interest
    3,257        15,569   
 
           
Total CO2 and other non-hydrocarbon gases capital expenditures
    38,609        70,449   
 
           
Total capital expenditures excluding acquisitions
    243,923        197,693   
 
           
Oil and natural gas property acquisitions
    29,801        340   
Consideration for Encore Merger(1)
          2,952,515   
 
           
Total
   $ 273,724       $ 3,150,548   
 
           
 
(1)  
Consideration given in Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued.
     Our capital expenditures for the first three months of 2011 were funded with $124.8 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 three months of 2010, excluding the Encore Merger, were funded with $113.2 million of cash flow from operations and proceeds from the sale of our interests in Genesis.
     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.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     In April 2011, we entered into three long-term drilling contracts. Our total commitment under these contracts is approximately $55.8 million, with $5.2 million expected to be paid in 2011, $18.6 million in both 2012 and 2013, and $13.4 million in 2014.
     Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and the section entitled Off-Balance Sheet Arrangements – Commitments and Obligations contained in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding our commitments and obligations. Also see Overview – CO2 Purchase Contracts for discussion of additional purchase contracts we entered into during the first quarter of 2011.
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 first quarter of 2011, our CO2 production at Jackson Dome averaged 1,021 MMcf/d as compared to an average of 802 MMcf/d produced during the first quarter of 2010 and 974 MMcf/d produced during the fourth quarter of 2010. We used 91% of this production, or 926 MMcf/d, in our tertiary operations during the first 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 spent approximately $0.25 per Mcf in operating expenses to produce our CO2 during the first three months of 2011, which is up significantly from our $0.20 per Mcf cost during the first three months 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 quarter of 2011:
                                           
    Average Daily Production (Bbls/d)
    First     Second     Third     Fourth       First  
    Quarter     Quarter     Quarter     Quarter       Quarter  
Tertiary Oil Field   2010     2010     2010     2010       2011  
           
Phase 1:
                                         
Brookhaven
    3,416       3,277       3,323       3,699         3,664  
McComb area
    2,289       2,160       2,484       2,433         2,161  
Mallalieu area
    3,443       3,628       3,279       3,164         2,925  
Other
    2,817       3,282       3,343       3,361         3,290  
Phase 2:
                                         
Heidelberg
    1,708       1,857       2,806       3,422         3,374  
Eucutta
    3,792       3,625       3,284       3,286         3,247  
Soso
    3,213       3,207       3,016       2,828         2,582  
Martinville
    927       764       606       586         500  
Phase 3:
                                         
Tinsley
    4,419       5,248       6,024       6,614         6,567  
Phase 4:
                                         
Cranfield
    936       811       855       1,043         991  
Phase 5:
                                         
Delhi
    63       648       511       703         1,524  
           
Total tertiary oil production
    27,023       28,507       29,531       31,139         30,825  
           
 
                                         
Tertiary operating expense per Bbl
    $ 22.67       $ 21.37       $ 22.54       $ 22.26         $ 25.40  
           
     Oil production from our tertiary operations increased to an average of 30,825 Bbls/d during the first quarter of 2011, a 14% increase over our first quarter of 2010 tertiary production level of 27,023 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 Mallalieu, Soso, and Eucutta Fields, production from which has most likely peaked and will likely continue to decline in the future.
     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 lack of 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. We expect our tertiary production to resume its growth later this year, as these temporary fluctuations have not changed our overall outlook for these fields.
     With the Green Pipeline complete, 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 or early 2012, depending on the date of completion of our CO2 recycle facilities at this field. We anticipate first production at Oyster Bayou Field late in the first quarter of 2012, also dependant on the completion of CO2 recycle facilities. We received the regulatory approvals required to commence construction of the CO2 recycling facilities at Hastings and Oyster Bayou Fields in the fourth quarter of 2010, after extensive unforeseen regulatory delays, and began construction of these facilities in the first quarter of 2011.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     During the first quarter of 2011, operating costs for our tertiary properties averaged $25.40 per Bbl, compared to our first quarter of 2010 average cost of $22.67 per Bbl and a fourth quarter of 2010 average of $22.26 per Bbl. The per Bbl increase quarter to quarter was primarily due to increases in utilities, CO2 costs (which are variable and partially tied to oil prices), and workover expenses. On a per Bbl basis, our cost of CO2 increased by $0.69 per Bbl, from $4.89 per Bbl during the first quarter of 2010 to $5.58 per Bbl during the first quarter of 2011 and increased $0.03 from $5.55 per Bbl during the fourth quarter of 2010 due to slightly lower CO2 injection levels at our tertiary producing fields. First quarter of 2011 workover expenses increased $1.32 per Bbl over the first quarter of 2010 levels and $1.39 per Bbl over fourth quarter of 2010 levels as we accelerated planned mechanical integrity test repairs at Brookhaven Field rather than performing the work throughout the year as originally planned. 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 Bbl will again increase.
Operating Results
     Certain of our operating results and statistics for the first three months of 2011 and 2010 are included in the following table:
                 
    Three Months Ended
    March 31,
In thousands, except per share and unit data   2011   2010 (1)
         
Operating results:
               
Net income (loss) attributable to Denbury stockholders
  $ (14,190 )     $ 96,888  
Net income (loss) per common share - basic
    (0.04 )     0.33  
Net income (loss) per common share - diluted
    (0.04 )     0.32  
Cash flow from operations
    124,832       113,168  
Average daily production volumes:
               
Bbls/d
    58,460       44,309  
Mcf/d
    30,866       52,892  
BOE/d
    63,604       53,125  
Operating revenues:
               
Oil sales
  $ 492,838     $ 305,204  
Natural gas sales
    13,354       25,682  
         
Total oil and natural gas sales
  $ 506,192     $ 330,886  
         
Commodity derivative contracts: (2)
               
Net cash receipts (payments) on settlement of commodity derivative contracts
  $ 1,588     $ (59,801 )
Non-cash fair value adjustment income (expense)
    (172,338 )     100,839  
         
Total income (expense) from commodity derivative contracts
  $ (170,750 )   $ 41,038  
         
Operating expenses:
               
Lease operating
  $ 127,097     $ 96,220  
Production taxes and marketing
    32,751       19,317  
         
Total production expenses
  $ 159,848     $ 115,537  
         
Unit prices - including impact of derivative settlements: (2)
               
Oil price per Bbl
  $ 92.72     $ 60.60  
Natural gas price per Mcf
    7.19       6.18  
Unit prices - excluding impact of derivative settlements: (2)
               
Oil price per Bbl
  $ 93.67     $ 76.53  
Natural gas price per Mcf
    4.81       5.40  
Oil and natural gas operating revenues and expenses per BOE:
               
Oil and natural gas revenues
  $ 88.42     $ 69.21  
         
                 
Oil and natural gas lease operating expenses
  $ 22.20     $ 20.12  
Oil and natural gas production taxes and marketing expense
    5.72       4.04  
         
Total oil and natural gas production expenses
  $ 27.92     $ 24.16  
         
(1)   Includes the results of operations of Encore properties and ENP from March 9, 2010 through March 31, 2010.
 
(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 quarter of 2011 are shown below:
                                                   
    Average Daily Production (BOE/d)
    First     Pro Forma     Second     Third     Fourth       First  
    Quarter     First Quarter     Quarter     Quarter     Quarter       Quarter  
Operating Area
  2010 (1)     2010 (2)     2010     2010     2010       2011  
           
Gulf Coast Region:
                                                 
Tertiary oil fields
    27,023       27,023       28,507       29,531       31,139         30,825  
Non-tertiary fields:
                                                 
Mississippi
    7,829       7,829       8,967       7,965       7,293         7,586  
Texas
    5,235       5,235       5,148       4,824       4,564         4,371  
Louisiana
    662       662       775       714       687         767  
Alabama and other
    997       997       1,078       1,091       1,026         1,026  
           
Total Gulf Coast Region
    41,746       41,746       44,475       44,125       44,709         44,575  
 
                                                 
Rocky Mountain Region:
                                                 
Cedar Creek Anticline
    2,537       9,830       9,967       9,791       9,328         9,163  
Bakken
    890       3,549       4,500       4,657       5,193         5,728  
Bell Creek
    252       966       997       994       957         890  
Paradox
    173       675       702       738       716         635  
Other
    777       2,925       2,944       2,889       2,809         2,613  
           
Total Rocky Mountain Region
    4,629       17,945       19,110       19,069       19,003         19,029  
 
                                                 
           
Total Continuing Production
    46,375       59,691       63,585       63,194       63,712         63,604  
           
 
                                                 
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  
           
 
                                                 
           
  (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.
     As outlined in the above table, continuing production during the three months ended March 31, 2011 increased 7% over first quarter 2010 pro forma production levels. These increases were primarily due to the additional production from a 14% increase in our tertiary production and a 61% increase in production from the Bakken, partially offset by normal declines in most of our other properties or declines resulting from a conversion of a portion of the field to a tertiary flood. 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.
     Production from our Bakken properties averaged 5,728 BOE/d in the first quarter, a 61% increase from first quarter 2010 pro forma production levels and an increase of over 10% as compared to fourth quarter 2010 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. We anticipate adding a sixth rig in the third quarter of 2011 to test our acreage in the Almond area, and will likely add a seventh rig by the end of 2011. Our first quarter 2011 Bakken production was negatively impacted by severe winter weather which caused delays in well completions.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Our production during the three months ended March 31, 2011 was 92% oil as compared to 83% during the three months ended March 31, 2010. This increase is due to the sales of the non-strategic Encore properties and ENP properties in the second half of 2010, which had a higher percentage of natural gas production.
     Oil and Natural Gas Revenues. Due to the significant increase in oil prices between the first three months of 2010 and 2011, our oil and natural gas revenues increased sharply during the first quarter of 2011 as compared to revenues in the first quarter of 2010. 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 March 31,
    2011 vs. 2010
            Percentage
    Increase in   Increase in
In thousands   Revenues   Revenues
         
Change in oil and natural gas revenues due to:
               
Increase in commodity prices
  $ 110,042       33 %
Increase in production
    65,264       20 %
         
Total increase in oil and natural gas revenues
  $ 175,306       53 %
         
     Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first three month period of 2011 and 2010:
                 
    Three Months Ended  
    March 31,
    2011   2010
         
Net Realized Prices:
               
Oil price per Bbl
  $ 93.67     $ 76.53  
Natural gas price per Mcf
    4.81       5.40  
Price per BOE
    88.42       69.21  
 
               
NYMEX Differentials:
               
Oil per Bbl
  $ (0.59 )   $ (2.08 )
Natural gas per Mcf
    0.61       0.37  
     Our oil NYMEX differential improved during the three months ended March 31, 2011 as compared to our differential in the comparable period of 2010, primarily due to the favorable differential for crude oil sold under Light Louisiana Sweet (“LLS”) index prices, which are the sales prices for approximately 40% of our oil production. During the latter part of the first quarter, the LLS index price increased significantly more than increases in the NYMEX West Texas Intermediate crude oil price, trading as high as $20 over NYMEX. For the first quarter of 2011 this LLS-to-NYMEX differential averaged a positive $9.52 per barrel on a trade-month basis, as compared to a $4.07 differential in the fourth quarter of 2010 and a more typical $2.06 in the first quarter of 2010. While this differential is a significant portion of the pricing formula for approximately 40% of our oil production, other factors may prevent us from realizing the full differential. It is uncertain how long this LLS-to-NYMEX differential will remain at this level. Our oil price differential in the first quarter of 2010 was $2.08 per Bbl below NYMEX, which reflected only a partial period for the acquired Encore properties, which typically receive lower oil prices than our legacy production.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Commodity Derivative Contracts. The following tables summarize the impact that our commodity derivative contracts had on our operating results for the three months ended March 31, 2011 and 2010:
                                                 
    Three Months Ended March 31,
    2011   2010   2011   2010   2011   2010
    Oil   Natural Gas   Total Commodity
In thousands   Derivative Contracts   Derivative Contracts   Derivative Contracts
             
Non-cash fair value gain (loss)
  $ (167,064 )   $ 61,821     $ (5,274 )   $ 39,018     $ (172,338 )   $ 100,839  
Cash settlement receipts (payments)
    (5,028 )     (63,550 )     6,616       3,749       1,588       (59,801 )
                             
Total
  $ (172,092 )   $ (1,729 )   $ 1,342     $ 42,767     $ (170,750 )   $ 41,038  
                             
     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 approximately 32% between the three months ended March 31, 2011 and 2010 primarily as a result of:
    the completion of the Encore Merger on March 9, 2010;
 
    our increasing emphasis on tertiary operations and additional tertiary fields moving into the productive phase (see discussion of those expenses under CO2 Operations);
 
    higher CO2 costs, primarily due to increasing oil prices (see discussion of those expenses under CO2 Operations);
 
    increasing personnel and related costs resulting primarily from the Encore Merger; and
 
    increased workover costs primarily in our CO2 operations (see discussion of those expenses under CO2 Operations).
     Lease operating expense per BOE averaged $22.20 per BOE for the three months ended March 31, 2011, as compared to $20.12 per BOE for the same period in 2010. Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $25.40 per BOE during the three months ended March 31, 2011, compared to $22.67 per BOE for the same period in 2010. See CO2 Operations for a more detailed discussion.
     Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes, and as such, increased 70% during the three months ended March 31, 2011, as compared to the same period in 2010. This compares to an increase in oil and natural gas revenues of 53% during the three months ended March 31, 2011. The addition of properties in other operating areas acquired in the Encore Merger also affected these costs. Transportation and plant processing fees increased approximately $1.4 million during the three months ended March 31, 2011 and 2010, primarily due to the addition of properties in other operating areas acquired in the Encore Merger.
General and Administrative Expenses
     General and administrative (“G&A”) expenses increased on both a gross and per BOE basis between the three months ended March 31, 2011 and 2010 as set forth below:
                 
    Three Months Ended
    March 31,
In thousands, except per BOE data and employees   2011   2010
         
Gross cash G&A expense
  $ 67,697     $ 48,274  
Gross stock-based compensation
    11,337       9,939  
State franchise taxes
    1,159       1,070  
Operator labor and overhead recovery charges
    (29,716 )     (22,045 )
Capitalized exploration and development costs
    (6,631 )     (4,529 )
         
Net G&A expense
  $ 43,846     $ 32,709  
         
G&A per BOE:
               
Net cash G&A expense
  $ 5.86     $ 4.84  
Net stock-based compensation
    1.60       1.78  
State franchise taxes
    0.20       0.22  
         
Net G&A expense
  $ 7.66     $ 6.84  
         
Employees as of March 31
    1,182       1,251  
         

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Gross cash G&A expenses increased $19.4 million (40%) during the three months ended March 31, 2011, as compared to the same period of 2010, primarily due to the Encore Merger which closed March 9, 2010. The number of employees at March 31, 2011 compared to March 31, 2010 decreased by 6%, as many Encore employees who did not accept permanent positions with Denbury completed their pre-defined transition period in early 2011. However, compensation and personnel costs were less for the three months ended March 31, 2010, as the compensation and personnel costs for Encore employees were included in our G&A expenses beginning March 9, 2010, the date of the Encore Merger. Prior to the Encore Merger on March 9, 2010, our headcount was 856 employees. The largest increases were related to personnel costs, including salaries, payroll taxes and our 401(k) match. Wage increases also contributed to the increase in G&A, as we consider this necessary in order to remain competitive in our industry.
     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 quarter of 2011. Additionally, stock-based compensation expense increased $1.4 million when compared to levels in the same period of 2010, due primarily to the effect of Encore’s employees being included for a full quarter in 2011 versus only 22 days during the first quarter of 2010.
     The increase in gross G&A expense during the three months ended March 31, 2011, as compared to those costs in the same period 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 35% during the three months ended March 31, 2011, as compared to the same period in 2010. Capitalized exploration and development costs also increased between the periods, primarily due to increased compensation costs.
     The net effect of these changes resulted in a 34% increase (a 12% increase on a per BOE basis) in G&A expense between the comparable first quarters of 2011 and 2010.
Interest and Financing Expenses
                 
    Three Months Ended
    March 31,
In thousands, except per BOE data and interest rates   2011   2010
         
Cash interest expense
  $ 54,206     $ 44,974  
Non-cash interest expense
    5,528       2,754  
Less: capitalized interest
    (10,957 )     (21,312 )
         
Interest expense
  $ 48,777     $ 26,416  
         
Interest income and other
  $ (3,049 )   $ 1,870  
Net cash interest expense and other income per BOE (1)
  $ 7.10     $ 4.67  
Average debt outstanding
  $ 2,514,621     $ 2,225,700  
Average interest rate (2)
    8.3 %     8.1 %
 
(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.
     Interest expense increased $22.4 million during the three months ended March 31, 2011, as compared to the same period in 2010, primarily due to the increase in our average debt outstanding to finance the Encore Merger which closed in March 2010, a portion of which was repaid during 2010 with proceeds from the sale of non-strategic legacy Encore assets and our ENP ownership interest. The increase in interest expense between the comparative three month periods was also attributable to a 49% decrease in our capitalized interest relating primarily to the Green Pipeline, which was completed and placed into service during the second half of 2010.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
                 
Depletion, Depreciation, and Amortization      
    Three Months Ended  
    March 31,  
In thousands, except per BOE data   2011     2010  
Depletion, depreciation, and amortization (“DD&A”) of oil and natural gas properties
  $ 82,086     $ 71,197  
Depletion and depreciation of CO2 assets
    4,590       5,300  
Asset retirement obligations
    1,563       1,107  
Depreciation of other fixed assets
    5,355       4,268  
 
           
Total DD&A
  $ 93,594     $ 81,872  
 
           
 
               
DD&A per BOE:
               
Oil and natural gas properties
  $ 14.61     $ 15.12  
CO2 assets and other fixed assets
    1.74       2.00  
 
           
Total DD&A cost per BOE
  $ 16.35     $ 17.12  
 
           
     Depletion of oil and natural gas properties increased on an absolute dollars basis during the three months ended March 31, 2011 as compared to the same period of 2010, primarily due to the Encore Merger. However, on a per BOE basis, our DD&A expense decreased from quarter-to-quarter due to incremental production attributable to the properties acquired from Encore, the acquisition of Riley Ridge, and higher tertiary production in the first quarter of 2011.
     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 months ended March 31, 2011 compared to the prior periods 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 decreased for the three months ended March 31, 2011 compared to those in the prior year quarter due to increased oil and natural gas production volumes as a result of the Encore Merger, which closed in March 2010, and as a result of proved CO2 reserve additions noted above.
     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 March 31, 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 $2.4 million and $45.0 million for the three months ended March 31, 2011 and 2010, respectively, associated with the Encore Merger, including $1.8 million and $1.2 million, respectively, related to severance costs. 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  
    March 31,  
In thousands, except per BOE amounts and tax rates   2011     2010  
Current income tax provision (benefit)
  $ (848)     $ 669  
Deferred income tax provision (benefit)
    (7,908)       76,272  
 
           
Total income tax provision (benefit)
  $ (8,756)     $ 76,941  
 
           
Average income tax provision per BOE
  $ (1.53)     $ 16.09  
Effective tax rate
    38.2%       43.4%  
     Our income taxes are based on an estimated statutory rate of approximately 38%. Our effective tax rate for the first quarter of 2011 was slightly higher compared to our statutory rate, primarily due to nondeductible compensation. Our effective tax rate for the comparative quarter was higher than the historical statutory rate due to the remeasurement of our deferred tax liabilities as a result of the Encore Merger in the first quarter of 2010 that resulted in an additional income tax provision of approximately $10 million. During the three months ended March 31, 2010, the current income tax expense represented our state income taxes, primarily related to the sale of our interest in Genesis.
     As of March 31, 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 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.
     The current administration in Washington D.C. is attempting to remove 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 as well as the repeal of the immediate expensing of intangible drilling costs and tertiary injectant costs. It is uncertain whether or not the current administration will be successful in changing the laws, but if they were successful, it would likely increase the amount of cash taxes that we pay. Should cash taxes increase significantly, it could impact our forecasted 2011 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  
    March 31,
Per BOE data   2011   2010
Oil and natural gas revenues
  $ 88.42     $ 69.21  
Gain (loss) on settlements of derivative contracts
    0.28       (12.51 )
Lease operating expenses
    (22.20 )     (20.12 )
Production taxes and marketing expenses
    (5.72 )     (4.04 )
 
       
Production netback
    60.78       32.54  
Non-tertiary CO2 operating margin
    0.48       0.65  
General and administrative expenses
    (7.66 )     (6.84 )
Transaction and other costs related to the Encore Merger
    (0.41 )     (9.41 )
Net cash interest expense and other income
    (7.10 )     (4.67 )
Current income taxes and other
    1.29       1.53  
Changes in assets and liabilities relating to operations
    (25.57 )     9.87  
 
       
Cash flow from operations
    21.81       23.67  
DD&A
    (16.35 )     (17.12 )
Deferred income taxes
    1.38       (15.95 )
Gain on sale of interests in Genesis
    -       21.24  
Loss on early extinguishment of debt
    (2.76 )     -  
Non-cash fair value derivative adjustments
    (30.11 )     21.13  
Net income attributable to noncontrolling interest
    -       (0.69 )
Changes in assets and liabilities and other non-cash items
    23.55       (12.02 )
 
       
Net income (loss) attributable to Denbury stockholders
  $ (2.48 )   $ 20.26  
 
       
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.

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DENBURY RESOURCES INC.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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; unexpected difficulties in integrating the operations of Denbury and Encore; 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; 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 March 31, 2011:
                                                                         
    Expected Maturity Dates     Carrying     Fair  
In thousands, except percentages   2013     2014     2015     2016     2017     2020     2021     Value     Value  
Variable rate debt:
                                                                       
Bank Credit Agreement
  $ -     $ -     $ -     $ -     $ -     $ -     $ -     $ -     $ -  
Fixed rate debt:
                                                                       
7.5% Senior Subordinated Notes due 2013(1)
    55,448       -       -       -       -       -       -       55,352       55,448  
9.5% Senior Subordinated Notes due 2016
    -       -       -       224,920       -       -       -       238,826       253,597  
9.75% Senior Subordinated Notes due 2016
    -       -       -       426,350       -       -       -       405,283       480,710  
8.25% Senior Subordinated Notes due 2020
    -       -       -       -       -       996,273       -       996,273       1,113,335  
6.375% Senior Subordinated Notes due 2021
    -       -       -       -       -       -       400,000       400,000       410,000  
Other Subordinated Notes
    -       1,072       485       -       2,250       -       -       3,845       3,807  
 
(1) These notes were repurchased on April 1, 2011. See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements, for further information.
Commodity Derivative Contracts and Commodity Price Sensitivity
     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 (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 March 31, 2011, our commodity derivative contracts were recorded at their fair value, which was a net liability of approximately $216.3 million (excluding $21.2 million of deferred premiums that Denbury is obligated to pay for its derivative contracts, which payments are not subject to changes in commodity prices), a significant change from the $44.0 million fair value liability recorded at December 31, 2010. This change is primarily related to the oil futures prices as of March 31, 2011 in relation to the commodity derivative contracts for 2011 through 2012.

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DENBURY RESOURCES INC.
     Based on NYMEX crude oil and natural gas futures prices as of March 31, 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 March 31, 2011
  $ (120,867 )   $ 30,033  
10% increase in prices
    (308,210 )     21,692  
10% decrease in prices
    (11,555 )     38,358  
Equity Price Sensitivity
     Our investment in Vanguard common units is considered an investment in available-for-sale securities, which are 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 $10.0 million unrealized gain or loss, respectively, as of March 31, 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 March 31, 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 first 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 first 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  
January 2011
    84,250     $ 19.76       -     $ -  
February 2011
    36,513       22.46       -       -  
March 2011
    208,893       24.31       -       -  
 
                         
Total
    329,656       22.94       -     $ -  
 
                         
Item 6. Exhibits
     
Exhibit   Description
10(a)* **
  Form of 2011 Performance Share Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(b)* **
  Form of 2011 Performance Cash Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
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.
 
**   Compensation arrangements.

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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: May 10, 2011

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