XNYS:DNR Denbury Resources Inc Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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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, 2012

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

For the transition period from _______ to ________
 
Commission file number: 001-12935
 
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)

Delaware
 
20-0467835
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
     
5320 Legacy Drive,
Plano, TX
 
 
75024
(Address of principal executive offices)
 
(Zip Code)

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

Not applicable
(Former name, former address and former fiscal year, if changed since last report)
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes þ    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes þ   No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
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 30, 2012
Common Stock, $.001 par value
 
390,635,689
 



Table of Contents

       
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37
         
   
37
         
   
37
         
   
37
         
   
38
         
     
39
         
    Exhibit 4(a)    
    Exhibit 10(a)     
    Exhibit 10(b)    
    Exhibit 10(c)    
    Exhibit 31(a)    
    Exhibit 31(b)    
    Exhibit 32    
 


Denbury Resources Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
 
 
 
March 31,
   
December 31,
 
 
 
2012
   
2011
 
Assets
 
Current assets
 
 
   
 
 
Cash and cash equivalents
  $ 77,366     $ 18,693  
Restricted cash
    140,131        
Accrued production receivable
    303,552       294,689  
Trade and other receivables, net
    150,379       164,446  
Short-term investments
          86,682  
Derivative assets
    23,015       47,402  
Deferred tax assets
    47,641       50,156  
Other current assets
    15,951       22,045  
Total current assets
    758,035       684,113  
 
               
Property and equipment
               
Oil and natural gas properties (using full cost accounting)
               
Proved
    7,329,967       7,026,579  
Unevaluated
    995,352       1,157,106  
CO2 properties
    613,308       596,003  
Pipelines and plants
    1,755,679       1,701,756  
Other property and equipment
    162,363       157,674  
Less accumulated depletion, depreciation, amortization, and impairment
    (2,751,999 )     (2,627,493 )
Net property and equipment
    8,104,670       8,011,625  
 
               
Derivative assets
    1,245       29  
Goodwill
    1,236,318       1,236,318  
Other assets
    241,794       252,339  
Total assets
  $ 10,342,062     $ 10,184,424  
 
               
Liabilities and Stockholders' Equity
 
Current liabilities
               
Accounts payable and accrued liabilities
  $ 359,141     $ 429,336  
Oil and gas production payable
    196,622       197,092  
Derivative liabilities
    41,972       26,523  
Current maturities of long-term debt
    8,853       8,316  
Total current liabilities
    606,588       661,267  
 
               
Long-term liabilities
               
Long-term debt, net of current portion
    2,727,700       2,669,729  
Asset retirement obligations
    81,935       88,726  
Derivative liabilities
    22,013       18,872  
Deferred taxes
    1,953,253       1,918,576  
Other liabilities
    22,131       20,756  
Total long-term liabilities
    4,807,032       4,716,659  
 
               
 
               
Commitments and contingencies (Note 6)
               
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; 404,722,399 and 402,946,070 shares issued, respectively
    405       403  
Paid-in capital in excess of par
    3,102,617       3,090,374  
Retained earnings
    2,022,942       1,909,475  
Accumulated other comprehensive loss
    (400 )     (418 )
Treasury stock, at cost, 14,146,005 and 13,965,673 shares, respectively
    (197,122 )     (193,336 )
Total stockholders' equity
    4,928,442       4,806,498  
Total liabilities and stockholders' equity
  $ 10,342,062     $ 10,184,424  
 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
 
 
 
Three Months Ended
 
 
 
March 31,
 
 
 
2012
   
2011
 
Revenues and other income
 
 
   
 
 
Oil, natural gas, and related product sales
  $ 633,501     $ 506,192  
CO2 sales and transportation fees
    6,795       4,924  
Interest income and other income
    4,820       3,049  
Total revenues and other income
    645,116       514,165  
 
               
Expenses
               
Lease operating expenses
    137,964       123,797  
Marketing expenses
    10,830       5,303  
CO2 discovery and operating expenses
    6,205       1,946  
Taxes other than income
    43,694       32,483  
General and administrative
    36,607       42,319  
Interest, net of amounts capitalized of $19,445 and $10,957, respectively
    36,314       48,777  
Depletion, depreciation, and amortization
    120,895       93,594  
Derivatives expense
    45,275       170,750  
Loss on early extinguishment of debt
          15,783  
Impairment of assets
    17,300        
Other expenses
    10,720       2,359  
Total expenses
    465,804       537,111  
 
               
Income (loss) before income taxes
    179,312       (22,946 )
 
               
Income tax provision (benefit)
               
Current income taxes
    28,708       (848 )
Deferred income taxes
    37,137       (7,908 )
Net income (loss)
  $ 113,467     $ (14,190 )
 
               
 
               
Net income (loss) per common share – basic
  $ 0.29     $ (0.04 )
 
               
Net income (loss) per common share – diluted
  $ 0.29     $ (0.04 )
 
               
Weighted average common shares outstanding
               
Basic
    386,367       397,386  
Diluted
    390,943       397,386  
 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Unaudited Condensed Consolidated Statements of Comprehensive Operations
(In thousands)
 
 
 
Three Months Ended
 
 
  March 31,  
 
 
2012
   
2011
 
Net income (loss)
  $ 113,467     $ (14,190 )
Other comprehensive income, net of income tax:
               
Net unrealized gain 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 and $11, respectively
    18       17  
Total other comprehensive income     18       4,180  
Comprehensive income (loss)
  $ 113,485     $ (10,010 )
 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
 
 
 
Three Months Ended
 
 
 
March 31,
 
 
 
2012
   
2011
 
Cash flows from operating activities
 
 
   
 
 
Net income (loss)
  $ 113,467     $ (14,190 )
Adjustments needed to reconcile to net cash flow provided by operations:
               
Depletion, depreciation, and amortization
    120,895       93,594  
Deferred income taxes
    37,137       (7,908 )
Stock-based compensation
    7,913       10,201  
Noncash fair value derivative adjustments
    44,113       172,367  
Loss on early extinguishment of debt
          15,783  
Amortization of debt issuance costs and discounts
    3,674       5,051  
Impairment of assets
    17,300        
Other, net
    7,725       (3,681 )
Changes in operating assets and liabilities:
               
Accrued production receivable
    (8,863 )     (44,243 )
Trade and other receivables
    9,162       (17,484 )
Other current and long-term assets
    676       (8,449 )
Accounts payable and accrued liabilities
    (32,861 )     (90,382 )
Oil and natural gas production payable
    (470 )     18,770  
Other liabilities
    (28,214 )     (4,597 )
Net cash provided by operating activities
    291,654       124,832  
 
               
Cash flows from investing activities:
               
Oil and natural gas capital expenditures
    (302,246 )     (190,296 )
Acquisitions of oil and natural gas properties
    (592 )     (29,801 )
CO2 capital expenditures
    (30,693 )     (27,150 )
Pipelines and plants capital expenditures
    (60,441 )     (38,897 )
Purchases of other assets
    (4,945 )     (12,770 )
Net proceeds from sales of oil and natural gas properties and equipment
    166,703       11,989  
Addition to restricted cash
    (140,131 )      
Proceeds from sale of short-term investments
    83,545        
Other
    (83 )     1,882  
Net cash used for investing activities
    (288,883 )     (285,043 )
 
               
Cash flows from financing activities:
               
Bank repayments
    (150,000 )     (130,000 )
Bank borrowings
    210,000       130,000  
Repayment of senior subordinated notes
          (469,552 )
Premium paid on repayment of senior subordinated notes
          (13,137 )
Net proceeds from issuance of senior subordinated notes
          400,000  
Net proceeds from issuance of common stock
    3,949       5,253  
Costs of debt financing
    (11 )     (8,441 )
Other
    (8,036 )     (7,924 )
Net cash provided by (used for) financing activities
    55,902       (93,801 )
 
               
Net increase (decrease) in cash and cash equivalents
    58,673       (254,012 )
 
               
Cash and cash equivalents at beginning of period
    18,693       381,869  
 
               
Cash and cash equivalents at end of period
  $ 77,366     $ 127,857  
 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
 
Notes to Unaudited Condensed Consolidated Financial Statements
 
Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company.  We are the largest combined 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 our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011.  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” 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, 2012, our consolidated results of operations for the three months ended March 31, 2012 and 2011, and our consolidated cash flows for the three months ended March 31, 2012 and 2011.  Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.  On the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011, “Taxes other than income” is a new line item and includes oil and natural gas ad valorem taxes, which were reclassified from “Lease operating expenses,” franchise taxes and property taxes on buildings, which were reclassified from “General and administrative,” oil and natural gas production taxes, which were reclassified from “Production taxes and marketing expenses” used in prior reports and CO2 property ad valorem and production taxes, which were classified from “CO2 discovery and operating expenses.”  Such reclassifications had no impact on our reported total expenses or net income.

Restricted Cash

Restricted cash consists of proceeds from the sale of oil and gas properties in February 2012 that are held by a qualified intermediary and are restricted for the pending acquisition of Thompson Field (see Note 8, Subsequent Events) to facilitate an anticipated like-kind exchange transaction.
 
Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to common 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 to net income and common shares of the potential dilution from stock options, stock appreciation rights (“SARs”), nonvested restricted stock, and nonvested performance equity awards.  For the three months ended March 31, 2012 and 2011, there were no adjustments to net income for purposes of calculating diluted net income per common share.
 
 
Notes to Unaudited Condensed Consolidated Financial Statements
  
The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:

 
 
Three Months Ended
 
 
 
March 31,
 
In thousands
 
2012
   
2011
 
Basic weighted average common shares
    386,367       397,386  
Potentially dilutive securities:
               
Stock options and SARs
    3,330        
Performance equity awards
    117        
Restricted stock
    1,129        
Diluted weighted average common shares
    390,943       397,386  

Basic weighted average common shares excludes 3.9 million and 3.7 million shares of nonvested restricted stock during the three months ended March 31, 2012 and 2011, respectively.  As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, the nonvested 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 antidilutive:

 
 
Three Months Ended
 
 
 
March 31,
 
In thousands
 
2012
   
2011
 
Stock options and SARs
    3,179       12,641  
Restricted stock
    10       3,453  
Total
    3,189       16,094  

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 December 31, 2011, 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 Encore Energy Partners LP to a subsidiary of Vanguard on December 31, 2010.  We received distributions of $1.8 million on the Vanguard common units we owned for the three months ended March 31, 2011, which are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations.  During January 2012, the Company sold its investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees.  The Company recognized a pretax loss on the sale of $3.1 million, which is included in “Other expenses” on our Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012.

Recently Adopted Accounting Pronouncements

Comprehensive Income.  In June 2011, the Financial Accounting Standards Board (“FASB”) issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”).  ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements.  ASU 2011-05 was effective for Denbury beginning January 1, 2012.  Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.
 
 
Notes to Unaudited Condensed Consolidated Financial Statements
 
Fair Value.  In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”).  ASU 2011-04 amends the Financial Accounting Standards Board Codification (“FASC”) Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards.  ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements.  ASU 2011-04 was effective for Denbury beginning January 1, 2012.  The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures.  See Note 5, Fair Value Measurements.

Note 2. Acquisitions and Divestitures

Acquisitions

August 2011 Acquisition of Reserves in Rocky Mountain Region at Riley Ridge

In August 2011, we acquired the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming.  Riley Ridge contains natural gas resources, as well as helium and CO2 resources.  The purchase included a 57.5% interest in a gas plant which will separate the helium and natural gas from the commingled gas stream, and interests in certain surrounding properties.  The purchase price was approximately $214.8 million after closing adjustments, including a $15.0 million deferred payment to be made at the time the Riley Ridge gas plant is operational and meets specific performance conditions.  The gas plant is currently undergoing readiness testing, and we expect it to become operational during the fourth quarter of 2012.

The August 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized and no adjustments have been made to amounts previously disclosed in our Form 10-K for the period ended December 31, 2011.  Because the Riley Ridge plant is not yet operational, current production at the field is negligible.  As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011.

Divestitures

On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million.  We entered into the sales agreement with a privately held entity in which a member of our Board of Directors serves as chairman of the board, in a sale for which there was a competing bid contained in a multi-property purchase proposal.  On February 29, 2012, we closed on the sale with net proceeds of $144.8 million, after preliminary closing adjustments.  The sale had an effective date of December 1, 2011 and consequently, operating net revenues after the effective date, net of capital expenditures, along with any other purchase price adjustments, were adjustments to the selling price.  We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.
 
 
Notes to Unaudited Condensed Consolidated Financial Statements
 
Note 3. Long-Term Debt

The following table shows the components of our long-term debt:

 
 
March 31,
   
December 31,
 
In thousands
 
2012
   
2011
 
Bank Credit Facility
  $ 445,000     $ 385,000  
9½% Senior Subordinated Notes due 2016, including premium of $11,170 and $11,854, respectively
    236,090       236,774  
9¾% Senior Subordinated Notes due 2016, including discount of $16,783 and $17,854, respectively
    409,567       408,496  
8¼% Senior Subordinated Notes due 2020
    996,273       996,273  
6⅜% Senior Subordinated Notes due 2021
    400,000       400,000  
Other Subordinated Notes, including premium of $31 and $33, respectively
    3,838       3,840  
NEJD Pipeline financing
    162,704       163,677  
Free State Pipeline financing
    79,189       79,597  
Capital lease obligations
    3,892       4,388  
Total
    2,736,553       2,678,045  
Less current obligations
    (8,853 )     (8,316 )
Long-term debt and capital lease obligations
  $ 2,727,700     $ 2,669,729  

The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes.  DRI has no independent assets or operations.  Certain of DRI’s subsidiaries guarantee our debt, and each such subsidiary guarantor is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees are full and unconditional and joint and several obligations of the subsidiary guarantors.

Bank Credit Facility

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. as administrative agent, and other lenders party thereto (as amended the “Bank Credit Agreement”).  Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1 of each year and upon requested special redeterminations.  The borrowing base is adjusted at the banks’ discretion and is based in part upon certain external factors over which we have no control.  The weighted average interest rate on borrowings under the credit facility, evidenced by the Bank Credit Agreement (the “Bank Credit Facility”) was 2.0% for the three months ended March 31, 2012.  We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base.  The Bank Credit Agreement is scheduled to mature in May 2016.

In April 2012, we entered into the Seventh Amendment to the Bank Credit Agreement (the “Bank Amendment”).  Under the Bank Amendment, we increased the amount of additional permitted subordinate debt (other than refinancing debt) from $300.0 million to $650.0 million.  At the same time, the banks reaffirmed Denbury’s borrowing base of $1.6 billion under the Bank Credit Facility until the next redetermination, which is scheduled to occur on or around November 1, 2012.

6⅜% Senior Subordinated Notes due 2021

In February 2011, we issued $400.0 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393.0 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).
 
 
- 10 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
  
Redemption of our 2013 and 2015 Notes

On February 3, 2011, we commenced cash tender offers to purchase all $225.0 million principal amount of our 7½% Senior Subordinated Notes due 2013 (“2013 Notes”) and all $300.0 million principal amount of our 7½% Senior Subordinated Notes due 2015 (“2015 Notes”).  Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of par.  We called the remaining 2013 Notes and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011.  We recognized a $15.8 million loss during the three months ended March 31, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

Note 4.  Derivative Instruments

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; 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” 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 approximately 12 to 18 months in advance, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification.  We only enter into commodity derivative contracts with parties that are lenders under our Bank Credit Agreement.

The following is a summary of “Derivatives expense” included in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods indicated:

 
 
Three Months Ended
 
 
 
March 31,
 
In thousands
 
2012
   
2011
 
Oil
 
 
   
 
 
Payment on settlements of derivative contracts
  $ 8,230     $ 5,028  
Fair value adjustments to derivative contracts – expense
    42,445       167,064  
Total derivatives expense – oil
    50,675       172,092  
Natural Gas
               
Receipt on settlements of derivative contracts
    (7,040 )     (6,616 )
Fair value adjustments to derivative contracts – expense
    1,640       5,274  
Total derivatives income – natural gas
    (5,400 )     (1,342 )
Derivatives expense
  $ 45,275     $ 170,750  
 
 
- 11 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
 
Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables present outstanding commodity derivative contracts with respect to future production as of March 31, 2012:

 
 
 
       
Contract Prices(2)
 
 
 
Type of
       
 
   
Weighted Average Price
 
Year
Months
Contract
 
Volume(1)
   
Range
   
Swap
   
Floor
   
Ceiling
 
 
 
 
       
 
   
 
   
 
       
Oil Contracts:        
 
   
 
   
 
       
2012 
Apr – June
Swap
    625     $ 80.28 – 81.75     $ 81.04     $     $  
 
 
Collar
    53,000       70.00 – 137.50             70.00       119.44  
 
 
Put
    625       65.00 – 65.00             65.00        
Total Apr – June 2012
    54,250                                  
 
 
 
                                       
July – Sept
Swap
    625     $ 80.28 – 81.75     $ 81.04     $     $  
 
 
Collar
    53,000       80.00 – 140.65             80.00       128.57  
 
 
Put
    625       65.00 – 65.00             65.00        
Total July – Sept 2012
    54,250                                  
 
 
 
                                       
Oct – Dec
Swap
    625     $ 80.28 – 81.75     $ 81.04     $     $  
 
 
Collar
    53,000       80.00 – 140.65             80.00       128.57  
 
 
Put
    625       65.00 – 65.00             65.00        
Total Oct – Dec 2012
    54,250                                  
 
 
 
                                       
 
 
 
                                       
2013 
Jan – Mar
Swap
        $     $     $     $  
 
 
Collar
    55,000       70.00 – 117.00             70.00       110.32  
 
 
Put
                             
Total Jan – Mar 2013
    55,000                                  
 
 
 
                                       
Apr – June
Swap
        $     $     $     $  
 
 
Collar
    50,000       75.00 – 124.20             75.00       116.92  
 
 
Put
                             
Total Apr – June 2013
    50,000                                  
 
 
 
                                       
July – Sept
Swap
        $     $     $     $  
 
 
Collar
    50,000       75.00 – 133.10             75.00       122.14  
 
 
Put
                             
Total July – Sept 2013
    50,000                                  
 
 
 
                                       
Oct – Dec
Swap
        $     $     $     $  
 
 
Collar
    18,000       80.00 – 127.50             80.00       126.63  
 
 
Put
                             
Total Oct – Dec 2013
    18,000                                  
                                         
 
 
- 12 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
 
 
 
 
       
Contract Prices(2)
 
 
 
Type of
       
 
   
Weighted Average Price
 
Year
Months
Contract
 
Volume(1)
   
Range
   
Swap
   
Floor
   
Ceiling
 
 
 
 
       
 
   
 
   
 
       
Natural Gas Contracts:                                        
2012 
Apr – Dec
Swap
    20,000     $ 6.30 – 6.85     $ 6.53     $     $  
 
 
Collar
                             
 
 
Put
                             
Total Apr – Dec 2012
    20,000                                  
 
(1)
Contract volumes are stated in BBl/d and MMBtu/d for oil and natural gas contracts, respectively.
 
(2)
Contract prices are stated in $/BBl and $/MMBtu for oil and natural gas contracts, respectively.

Additional Disclosures about Derivative Instruments

At March 31, 2012 and December 31, 2011, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

 
 
 
 
 
 
 
Estimated Fair Value
 
 
 
 
 
 
 
Asset (Liability)
In thousands
 
 
 
March 31,
 
 
December 31,
Type of Contract
 
Balance Sheet Location
 
2012
 
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
 
Derivative asset
 
 
 
 
 
 
 
 
 
 
 
Crude oil contracts
 
Derivative assets – current
 
$
 705 
 
 
$
 23,452 
 
 
Natural gas contracts
 
Derivative assets – current
 
 
 22,310 
 
 
 
 23,950 
 
 
Crude oil contracts
 
Derivative assets – long-term
 
 
 1,245 
 
 
 
 29 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liability
 
 
 
 
 
 
 
 
 
 
 
Crude oil contracts
 
Derivative liabilities – current
 
 
 (40,212)
 
 
 
 (22,610)
 
 
Deferred premiums(1)
 
Derivative liabilities – current
 
 
 (1,760)
 
 
 
 (3,913)
 
 
Crude oil contracts
 
Derivative liabilities – long-term
 
 
 (22,013)
 
 
 
 (18,702)
 
 
Deferred premiums(1)
 
Derivative liabilities – long-term
 
 
 — 
 
 
 
 (170)
 
 
 
Total derivatives not designated as hedging instruments
 
$
 (39,725)
 
 
$
 2,036 

(1)
Deferred premiums payable relate to various oil and natural gas floor contracts and are payable on a monthly basis through January 2013.

Note 5.  Fair Value Measurements

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.  
 
 
- 13 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
  
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.  Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing.  The Company’s costless-collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, 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.

 
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).  The Company’s basis swaps are estimated using discounted cash flow calculations based upon forward commodity price curves.  Significant increases or decreases in forward commodity price curves would result in a significantly higher or lower fair value measurement.

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, 2012
 
 
 
Assets
 
 
   
 
   
 
   
 
 
Oil and natural gas derivative contracts
  $     $ 1,950     $ 22,310     $ 24,260  
Liabilities
                               
Oil and natural gas derivative contracts
          (62,225 )           (62,225 )
Total
  $     $ (60,275 )   $ 22,310     $ (37,965 )
 
                               
December 31, 2011
                               
Assets
                               
Short-term investments
  $ 86,682     $     $     $ 86,682  
Oil and natural gas derivative contracts
          23,481       23,950       47,431  
Liabilities
                               
Oil and natural gas derivative contracts
          (41,312 )           (41,312 )
Total
  $ 86,682     $ (17,831 )   $ 23,950     $ 92,801  
 
- 14 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
 
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” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
 
Level 3 Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table summarizes the changes in the fair value of our Level 3 assets for the three months ended March 31, 2012 and 2011:

 
  Three Months Ended  
 
  March 31,  
In thousands
 
2012
   
2011
 
Balance, beginning of period
  $ 23,950     $ 16,478  
Unrealized gains on commodity derivative contracts included in earnings
    5,400       310  
Payments on settlement of commodity derivative contracts
    (7,040 )     (1,442 )
Balance, end of period
  $ 22,310     $ 15,346  

We utilize an income approach to value our natural gas swap arrangements, generally the industry standard valuation technique for a commodity swap contract.  We obtain and ensure the appropriateness of the natural gas forward pricing curve, the most significant input to the calculation, and the fair value estimate is prepared and reviewed on a quarterly basis.
 
The following table details fair value inputs related to our level 3 financial measurements:

In thousands
 
Fair Value at 3/31/2012
 
Valuation Technique(s)
 
Unobservable Input
 
Range
Oil and natural gas derivative contracts
 
$
 22,310 
 
Discounted Cash Flow
 
Forward commodity price curve
 
(a)
 
(a)
The derivative instruments detailed in this category include non-exchange-traded natural gas derivatives swaps that are valued based on regional pricing other than NYMEX.  The regional pricing sources utilized for these instruments include the following (forward pricing ranges represent the high and low price expected to be received within the settlement period):
 
 
Pricing Index
 
Settlement Period
 
Forward Pricing Range
 
TETCO M1
 
4/1/2012 – 12/31/2012
 
$2.09/MMBtu – $3.21/MMBtu
 
Houston Ship Channel
 
4/1/2012 – 12/31/2012
 
$2.06/MMBtu – $3.09/MMBtu
 
Natural Gas – Midcontinent
 
4/1/2012 – 12/31/2012
 
$1.98/MMBtu – $3.05/MMBtu
 
 
- 15 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

As of December 31, 2011, we had invested a total of $13.8 million in the preferred stock of Faustina Hydrogen Products LLC, a company created to develop a proposed gasification plant from which CO2 would be produced as a byproduct and used by Denbury in its tertiary oil operations.  The investment was recorded at cost, together with a $1.3 million receivable for accrued dividends receivable.  The developer of the proposed plant was soliciting other potential investors for the project, and as of December 31, 2011, a third-party was actively engaged in due diligence.  During 2012, a key investor and participant in the project announced its intent to abandon its investment in the proposed plant.  As a result, due diligence by the potential third party investor ceased.  Absent the key investor, we believe it is unlikely the plant will be constructed and therefore, it is also unlikely our investment will generate future cash flows.  Accordingly, we recorded a $15.1 million impairment charge for this investment during the first quarter of 2012, which is classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statements of Operations.  The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset.  These inputs are unobservable within the marketplace and therefore considered level 3 within the fair value hierarchy.  However, as there are currently no expected future cash flows associated with the plant, the fair value was determined to be $0.

Other Fair Value Measurements

The carrying value of our Bank Credit Facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.  The fair values of our senior subordinated notes are based on quoted market prices.  The estimated fair value of our senior subordinated notes as of March 31, 2012 and December 31, 2011 is $2,255.5 million and $2,253.2 million, respectively.  The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets).  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. Commitments and Contingencies

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.  We are also 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.  Currently, we have no material assessments for potential taxes.
 
Note 7. Related Party

During the first quarter of 2012, we purchased and marketed $1.2 million of oil produced by a privately-held entity of which a member of our Board of Directors serves as chairman of the board.  The oil purchased under this agreement is related to the non-core assets in central and southern Mississippi and in southern Louisiana (see further discussion in Note 2, Acquisitions and Divestitures) sold to this same entity.  We are under no obligation to purchase oil under this agreement.

In addition, during the first quarter of 2012, we entered into a sublease of excess office space at our former corporate headquarters with the same privately-held entity.  The sublease provides for payment of $2.4 million in lease rentals to us over the lease term, which expires on July 31, 2016.  During the first quarter of 2012, we recorded $27 thousand in lease income related to the new sublease arrangement, which is classified as “Interest income and other income” in the Unaudited Condensed Consolidated Statements of Operations.
 
 
- 16 -

 
Notes to Unaudited Condensed Consolidated Financial Statements
 
Note 8. Subsequent Events

Sale of Non-Core Assets

On April 11, 2012, we announced that we had entered into an agreement and closed on the sale of certain non-operated assets in the Paradox Basin of Utah for $75 million.  The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million.  Preliminary closing adjustments include operating net revenues after January 1, 2012, net of capital expenditures, along with other purchase price adjustments.

Amendment to Bank Credit Agreement

During April 2012, we entered into an amendment to our Bank Credit Agreement (see Note 3, Long-Term Debt).

Pending Acquisition of Thompson Field

In April 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash.  Under the agreement, the seller will hold approximately a 5% net revenue interest beginning when average monthly tertiary oil production exceeds 3,000 Bbls/d.  Thompson Field is a significant potential tertiary oil flood located approximately 18 miles west of our Hastings Field, our most recent CO2 flood.  The acquisition is expected to close in June 2012.
 
 
- 17 -

 
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, 2011 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein 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 Part II of this report, along with Forward-Looking Information at the end of this Item 2 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 combined 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

We recognized net income of $113.5 million, or $0.29 per basic common share, during the first quarter of 2012 compared to a net loss of $14.2 million, or $0.04 per basic common share, during the first quarter of 2011.  This increase in net income between the two periods is primarily attributable to:

·  
an increase in oil and natural gas revenues of $127.3 million resulting from increased production ($69.4 million) and higher realized commodity prices ($57.9 million); and

·  
a decrease in expenses of $71.3 million, the largest of which was a reduction of the non-cash loss in the fair value of the Company’s commodity derivative contracts of $128.3 million, principally due to the change in NYMEX oil futures prices relative to our derivative contracts in place during each period, offset in part by other expense increases.

During the first quarter of 2012, our oil and natural gas production, which was 93% oil, averaged 71,532 BOE/d compared to 63,604 BOE/d produced during the first quarter of 2011.  This 12% increase in production is primarily attributable to increases in our Bakken and tertiary oil production, partially offset by normal declines in most of our other non-tertiary properties.  After adjusting quarterly production in both periods to exclude production from non-core properties which were sold in 2012 (see Sale of Non-Core Assets below), continuing production in the first quarter of 2012 increased 14% over production in the comparable prior year quarter and 7% sequentially over levels in the fourth quarter of 2011.  Our tertiary oil production averaged 33,257 Bbls/d during the first quarter of 2012, an increase of 8% over the 30,825 Bbls/d produced during the first quarter of 2011 and 7% over fourth quarter 2011 levels.  Our Bakken oil production averaged 15,114 BOE/d during the first quarter of 2012, an increase of 164% over production of 5,728 BOE/d during the first quarter of 2011, and 29% over levels in the fourth quarter of 2011.  See Results of Operations — CO2 Operations and Results of Operations — Operating Results — Production for more information.

Oil prices during the first quarter of 2012 were considerably higher than prices during the first quarter of 2011, with average NYMEX oil prices averaging $102.89 per Bbl in the first quarter of 2012, compared to average NYMEX prices of $94.26 per Bbl during the first quarter of 2011.  Our average realized oil price received per barrel, excluding the impact of commodity derivative contracts, was $102.52 per Bbl during the first quarter of 2012, compared to $93.67 per Bbl during the first quarter of 2011, a 9% increase between the comparative periods.  See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information on our oil prices received and differentials to NYMEX prices.
 
 
- 18 -

 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Sale of Investment in Vanguard Natural Resources LLC

On January 19, 2012, we sold our investment in Vanguard Natural Resources LLC (“Vanguard”) common units for cash consideration of $83.5 million, net of related transaction fees. The investment was originally acquired as partial consideration for the sale of our interests in Encore Energy Partners LP on December 31, 2010.  In connection with the sale, during the first quarter of 2012 we recorded a pretax $3.1 million loss which is classified as “Other expenses” in the Unaudited Condensed Consolidated Statements of Operations.   The $3.1 million loss represents the difference between the net proceeds received from the sale and the carrying amount of the investment at December 31, 2011.

Sale of Non-Core Assets

On January 10, 2012, we entered into an agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155 million.  On February 29, 2012, we closed the sale for net proceeds of $144.8 million, after preliminary closing adjustments.  The sale had an effective date of December 1, 2011 and consequently operating net revenues after December 1, 2011, net of capital expenditures, along with any other purchase price adjustments, reduced the selling price.  We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

On April 11, 2012, we announced that we had entered into an agreement and closed the sale of non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah for $75 million.  The sale had an effective date of January 1, 2012 and proceeds received after consideration of preliminary closing adjustments totaled $72.4 million.

Addition of Proved Oil and Natural Gas Reserves

During the first quarter of 2012, we added 18.3 MMBOE of estimated proved reserves, including 14.0 MMBOE at Oyster Bayou Field based on the field’s recent response to CO2 injections, and 4.3 MMBOE due to further development in the Bakken.  These increases were partially offset by the disposition of 6.6 MMBOE of reserves associated with certain non-core Gulf Coast assets we sold in February 2012, as discussed above.

Pending Acquisition of Thompson Field

On April 24, 2012, we entered into an agreement to purchase a nearly 100% working interest and 84.7% net revenue interest in Thompson Field located in southeast Texas for approximately $360 million in cash.  Under the agreement, the seller will hold approximately a 5% net revenue interest when average monthly tertiary oil production exceeds 3,000 Bbls/d.  Thompson Field is a significant potential tertiary oil flood and is located approximately 18 miles west of our Hastings Field.  Net to Denbury’s interest, Thompson Field is producing approximately 2,200 Bbls/d of oil, roughly equivalent to the daily production volumes of our non-core assets divested to date in 2012, as discussed above, all of which is non-tertiary production.  The sale has an effective date of June 1, 2012 and is expected to close in June 2012.
 
 
- 19 -

 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Capital Resources and Liquidity

We recently increased our projected 2012 capital budget from $1.35 billion to $1.5 billion based on higher than previously estimated cash flows as a result of better than expected commodity prices and production.  We allocated $80 million of our capital budget to further develop the Bakken, $65 million to tertiary oilfield expenditures (primarily in the Hastings and Bell Creek fields) and the remainder to other capital spending projects.  Our capital budget of $1.5 billion excludes estimated equipment leases ($75 million), acquisitions, capitalized interest and start-up costs associated with our new tertiary floods.  Our current 2012 capital budget includes the following:

·  
$430 million allocated for tertiary oil field expenditures;
·  
$480 million for development of our Bakken properties;
·  
$290 million for pipeline construction;
·  
$200 million to be spent on CO2sources; and
·  
$100 million to be spent in all other areas.

Based on oil and natural gas prices in early May 2012 and our current production forecasts, we estimate that our 2012 capital budget (including capitalized interest and tertiary start-up costs) will be approximately $100 to $200 million greater than our 2012 anticipated cash flow from operations.  We plan to fund any shortfall between our cash flow from operations and our capital spending with our asset sales and borrowings under our Bank Credit Facility.

During the first three months of 2012, we incurred capital expenditures of approximately $319.8 million, net of equipment lease recoveries of $21.0 million.  Additionally, we have capitalized interest and tertiary start-up costs which are not included in the above mentioned amounts.  See additional detail on our expenditures in the table below.

During the first four months of 2012, we received net proceeds from non-core oil and natural gas asset divestitures of $217.2 million ($144.8 million at March 31, 2012 and $72.4 million during April 2012), $212.5 million of which are being held by a qualified intermediary to facilitate an anticipated like-kind exchange transaction.  We plan to use these proceeds, together with borrowings under our Bank Credit Facility, to fund the $360 million acquisition of Thompson Field, which is expected to close in early June 2012.  See Sale of Non-Core Assets and Pending Acquisition of Thompson Field discussed above.  In structuring these transactions as a like-kind exchange for income tax purposes, we anticipate deferral of a majority of the taxable gain recognized on the sale of the non-core assets.  Such amounts are classified as “Restricted cash” on the Unaudited Condensed Consolidated Balance Sheet.
 
In October 2011, we commenced a share repurchase program for up to $500 million of Denbury common stock.  To date we have only repurchased $195.2 million (all during the fourth quarter of 2011).  Any further share repurchases during 2012 will be determined based on various parameters; therefore, it is uncertain whether or not we will make additional share repurchases of Denbury common stock under this program in the remainder of 2012.

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 2012 and certain future years, we have contracted for certain capital expenditures; 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 the Form 10-K).  In addition to the potential flexibility in our capital spending plans, as of March 31, 2012, we had approximately $1.2 billion of unused liquidity under our Bank Credit Facility and have oil price floors in place through 2013 (see Note 4, Derivative Instruments, to the Unaudited Condensed Consolidated Financial Statements), which together should provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly.  Also, we currently believe we could significantly expand our borrowing base beyond the current $1.6 billion if we desired to do so.
 
 
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Capital Expenditure Summary

The following table of capital expenditures includes accrued capital for the three months ended March 31, 2012 and 2011:

 
 
Three Months Ended
 
 
 
March 31,
 
In thousands
 
2012
   
2011
 
Capital expenditures by project:
 
 
   
 
 
Tertiary oil fields
  $ 113,578     $ 100,984  
Bakken
    122,500       61,358  
CO2 pipelines
    14,151       3,497  
CO2 properties
    18,161       20,306  
Other areas
    72,373       46,310  
 
               
Capital expenditures before acquisitions and capitalized interest
    340,763       232,455  
 
               
Less: recoveries from sale/leaseback transactions
    (21,002 )     (2,445 )
 
               
Net capital expenditures excluding acquisitions and capitalized interest
    319,761       230,010  
 
               
Acquisitions:
               
Property acquisitions
    1,234       29,801  
 
               
Capitalized interest
    19,445       10,957  
 
               
Capital expenditures, net of sale/leaseback transactions
  $ 340,440     $ 270,768  

Our capital expenditures for the first three months of 2012 were funded with $291.7 million of cash flow from operations and the remainder with borrowings under our Bank Credit Facility.  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.

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.

Our commitments and obligations consist of those detailed as of December 31, 2011 in the Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of OperationsOff-Balance Sheet Arrangements – Commitments and Obligations.
 
 
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Results of Operations

CO2 Operations

Our focus on CO2operations is the primary strategy of our business and operations.  We believe there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this estimated potential in our Form 10-K 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 Form 10-K for further information regarding these matters.

During the first quarter of 2012, our CO2 production at Jackson Dome averaged 1,047 MMcf/d, compared to an average of 1,021 MMcf/d produced during the first quarter of 2011 and 1,024 MMcf/d produced during the fourth quarter of 2011.  We used 92% of this production, or 964 MMcf/d, in our tertiary operations during the first quarter of 2012, and sold the balance to our industrial customers or to Genesis Energy, L.P. 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 Form 10-K for further discussion of our CO2 delivery obligations.  We believe we have sufficient CO2reserves to develop our current Gulf Coast enhanced oil recovery program, and we continue to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome.  At December 31, 2011, our proven CO2 reserves at Jackson Dome were approximately 6.7 Tcf.

We spent approximately $0.28 per Mcf in operating expenses to produce our CO2 during the first quarter of 2012, which costs averaged $0.25 per Mcf during the first quarter of 2011 and the fourth quarter of 2011.  This increase in the rate from the prior year quarters is due primarily to increased CO2 royalty expense (which is tied to oil prices) and an increase in lease operating expense charges.
 
 
- 22 -

 
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 barrel for each quarter in 2011 and the first quarter of 2012:

   
Average Daily Production (Bbl/d)
 
   
First
   
Second
   
Third
   
Fourth
   
First
 
   
Quarter
   
Quarter
   
Quarter
   
Quarter
   
Quarter
 
Tertiary Oil Field
 
2011
   
2011
   
2011
   
2011
   
2012
 
Phase 1:
 
 
   
 
   
 
   
 
   
 
 
Brookhaven
    3,664       3,213       3,030       3,121       3,014  
McComb area
    2,161       1,983       2,005       1,843       1,746  
Mallalieu area
    2,925       2,646       2,620       2,587       2,585  
Other
    3,290       3,196       2,879       2,749       2,500  
Phase 2:
                                       
Heidelberg
    3,374       3,548       3,141       3,728       3,583  
Eucutta
    3,247       3,114       2,985       3,139       3,090  
Soso
    2,582       2,317       2,331       2,162       2,063  
Martinville
    500       416       453       481       551  
Phase 3:
                                       
Tinsley
    6,567       6,990       7,075       6,338       7,297  
Phase 4:
                                       
Cranfield
    991       1,085       1,214       1,200       1,152  
Phase 5:
                                       
Delhi
    1,524       2,263       3,358       3,778       4,181  
Phase 7:(1)