10-Q 1 form10q.htm FORM 10-Q form10q.htm


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 September 30, 2011

o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
     
     
Delaware
 
20-0467835
 
 (State or other jurisdictions of
incorporation or organization)
 
(I.R.S. Employer Identification No.)
     
5320 Legacy Drive
Plano, TX
 
 
75024
(Address of principal executive offices)
 
(Zip Code)

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

Not applicable
(Former name, former address and former fiscal year, if changed since last report)

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

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

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

Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
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 November 1, 2011
Common Stock, $.001 par value
 
391,624,449
 
 
 


 


INDEX

           
   
Page
 
PART I. FINANCIAL INFORMATION
           
Item 1. Financial Statements
         
           
   
3
   
           
   
4
   
           
   
5
   
           
   
6
   
           
   
7
   
           
   
18
   
           
   
31
   
           
   
32
   
           
PART II. OTHER INFORMATION
           
   
33
   
           
   
33
   
           
   
33
   
           
   
33
   
           
   
34
   
           

 
- 2 -

DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)

 
September 30,
 
December 31,
 
 
2011
 
2010
 
ASSETS
 
Current assets
           
Cash and cash equivalents
  $ 24,363     $ 381,869  
Accrued production receivable
    264,999       223,584  
Trade and other receivables, net of allowance of $274 and $456, respectively
    176,734       114,149  
Short-term investments
    81,851       93,020  
Derivative assets
    116,761       24,242  
Deferred tax assets
    -       27,454  
Total current assets
    664,708       864,318  
                 
Property and equipment
               
Oil and natural gas properties (using full cost accounting)
               
Proved
    6,763,404       6,042,442  
Unevaluated
    1,088,733       870,130  
CO2 and other non-hydrocarbon gases properties
    599,881       523,423  
Pipelines and plants
    1,598,098       1,378,239  
Other property and equipment
    142,243       120,641  
Less accumulated depletion, depreciation, amortization, and impairment
    (2,510,715 )     (2,197,517 )
Net property and equipment
    7,681,644       6,737,358  
                 
Derivative assets
    56,460       12,919  
Goodwill
    1,236,094       1,232,418  
Other assets
    248,027       218,050  
Total assets
  $ 9,886,933     $ 9,065,063  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
Current liabilities
               
Accounts payable and accrued liabilities
  $ 405,243     $ 350,068  
Oil and gas production payable
    183,521       143,145  
Derivative liabilities
    9,253       78,184  
Current maturities of long-term debt
    8,177       7,948  
Deferred taxes
    37,326       -  
Total current liabilities
    643,520       579,345  
                 
Long-term liabilities
               
Long-term debt, net of current portion
    2,396,549       2,416,208  
Asset retirement obligations
    87,725       81,290  
Derivative liabilities
    732       29,687  
Deferred taxes
    1,799,793       1,547,992  
Other liabilities
    22,842       29,834  
Total long-term liabilities
    4,307,641       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; 402,625,687 and 400,291,033 shares issued, respectively
    403       400  
Paid-in capital in excess of par
    3,085,862       3,045,937  
Retained earnings
    1,856,868       1,336,142  
Accumulated other comprehensive loss
    (7,361 )     (488 )
Treasury stock, at cost, 0 and 78,524 shares, respectively
    -       (1,284 )
Total stockholders' equity
    4,935,772       4,380,707  
Total liabilities and stockholders' equity
  $ 9,886,933     $ 9,065,063  

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
 

 
- 3 -

DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)


 
 
 
   
 
   
 
   
 
 
 
 
Three Months Ended
   
Nine Months Ended
 
 
 
September 30,
   
September 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
Revenues and other income
 
 
   
 
   
 
   
 
 
Oil, natural gas, and related product sales
  $ 565,523     $ 460,785     $ 1,662,814     $ 1,279,699  
CO2 sales and transportation fees
    6,541       4,653       16,808       13,840  
Gain on sale of interests in Genesis
    -       (3 )     -       101,537  
Interest income and other income
    4,441       1,268       12,445       7,658  
Total revenues and other income
    576,505       466,703       1,692,067       1,402,734  
 
                               
Expenses
                               
Lease operating expenses
    136,531       131,768       393,560       355,731  
Production taxes and marketing expenses
    36,949       35,542       109,388       92,959  
CO2 discovery and operating expenses
    1,358       2,488       5,381       5,537  
General and administrative
    28,906       37,115       103,652       101,016  
Interest, net of amounts capitalized of $17,853, $10,917, $42,004 and $56,079, respectively
    37,617       53,331       128,643       123,230  
Depletion, depreciation, and amortization
    101,978       111,602       299,067       322,683  
Derivatives expense (income)
    (210,154 )     31,854       (212,308 )     (138,045 )
Loss on early extinguishment of debt
    -       -       16,131       -  
Transaction and other costs related to the Encore Merger
    -       11,470       4,377       79,253  
Total expenses
    133,185       415,170       847,891       942,364  
 
                               
Income before income taxes
    443,320       51,533       844,176       460,370  
 
                               
Income tax provision (benefit)
                               
Current income taxes
    (5,331 )     3,704       5,849       11,314  
Deferred income taxes
    172,981       16,595       317,601       167,289  
 
                               
Consolidated net income
    275,670       31,234       520,726       281,767  
Less: net income attributable to noncontrolling interest
    -       (2,130 )     -       (20,408 )
Net income attributable to Denbury stockholders
  $ 275,670     $ 29,104     $ 520,726     $ 261,359  
 
                               
Net income per common share
                               
Basic
  $ 0.69     $ 0.07     $ 1.31     $ 0.72  
Diluted
  $ 0.68     $ 0.07     $ 1.29     $ 0.71  
 
                               
Weighted average common shares outstanding
                               
Basic
    399,040       395,913       398,371       362,241  
Diluted
    403,311       401,093       403,575       367,434  

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
 

 
- 4 -

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


 
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2011
   
2010
 
Cash flows from operating activities
 
 
   
 
 
Consolidated net income
  $ 520,726     $ 281,767  
Adjustments needed to reconcile to net cash provided by operating activities
               
Depletion, depreciation, and amortization
    299,067       322,683  
Deferred income taxes
    317,601       167,289  
Gain on sale of interests in Genesis
    -       (101,537 )
Stock-based compensation
    27,520       27,326  
Non-cash fair value derivative adjustments
    (217,092 )     (185,009 )
Loss on early extinguishment of debt
    16,131       -  
Other, net
    9,024       14,254  
Changes in operating assets and liabilities
               
Accrued production receivable
    (45,017 )     48,453  
Trade and other receivables
    (53,012 )     20,548  
Other assets
    2,818       1,106  
Accounts payable and accrued liabilities
    (65,407 )     8,257  
Oil and natural gas production payable
    40,819       10,553  
Other liabilities
    (14,086 )     (22,915 )
Net cash provided by operating activities
    839,092       592,775  
 
               
Cash flows used for investing activities
               
Oil and natural gas capital expenditures
    (741,256 )     (500,062 )
Acquisitions of oil and natural gas properties
    (34,291 )     (24,390 )
Cash paid in Encore Merger, net of cash acquired
    -       (813,894 )
Cash paid in Riley Ridge acquisition
    (199,233 )     -  
CO2 and other non-hydrocarbon gases capital expenditures
    (65,866 )     (67,328 )
Pipelines and plants capital expenditures
    (142,406 )     (169,157 )
Net proceeds from sales of oil and natural gas properties
    47,598       909,986  
Net proceeds from sale of interests in Genesis
    -       162,619  
Other
    (22,798 )     (17,927 )
Net cash used for investing activities
    (1,158,252 )     (520,153 )
 
               
Cash flows from financing activities
               
Bank repayments
    (255,000 )     (1,519,000 )
Bank borrowings
    365,000       1,229,000  
Repayment of senior subordinated notes
    (525,000 )     (609,424 )
Premium paid on repayment of senior subordinated notes
    (13,137 )     (7,213 )
Net proceeds from issuance of senior subordinated notes
    400,000       1,000,000  
Net proceeds from issuance of common stock
    12,348       8,614  
Costs of debt financing
    (13,104 )     (76,232 )
ENP distributions to noncontrolling interest
    -       (24,513 )
Other
    (9,453 )     (8,100 )
Net cash used for financing activities
    (38,346 )     (6,868 )
 
               
Net increase (decrease) in cash and cash equivalents
    (357,506 )     65,754  
Cash and cash equivalents at beginning of period
    381,869       20,591  
Cash and cash equivalents at end of period
  $ 24,363     $ 86,345  

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
 

 
- 5 -

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)


 
 
Three Months Ended
   
Nine Months Ended
 
 
 
September 30,
   
September 30,
 
 
 
2011
   
2010
   
2011
   
2010
 
Consolidated net income
  $ 275,670     $ 31,234     $ 520,726     $ 281,767  
Other comprehensive income, net of income tax
                               
Net unrealized loss on available-for-sale securities, net of tax benefit of $2,420 and $4,244, respectively
    (3,949 )     -       (6,925 )     -  
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $11, $32, and $32, respectively
    17       17       52       52  
Change in deferred hedge loss on interest rate swaps, net of tax benefit of $14 and $32, respectively
    -       (68 )     -       (155 )
Consolidated comprehensive income
    271,738       31,183       513,853       281,664  
Less: comprehensive income attributable to noncontrolling interest
    -       (2,074 )     -       (20,308 )
Comprehensive income attributable to Denbury stockholders
  $ 271,738     $ 29,109     $ 513,853     $ 261,356  

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
 

 
- 6 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements


Note 1. Basis of Presentation

Organization and Nature of Operations

We are a growing independent oil and natural gas company.  We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis on our CO2 tertiary recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by Accounting Principles Generally Accepted in the United States (“U.S. GAAP”) for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010.  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2011, our consolidated results of operations for the three and nine months ended September 30, 2011 and 2010, and our consolidated cash flows for the nine months ended September 30, 2011 and 2010. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Noncontrolling Interest

From March 9, 2010 to December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“GP LLC”), which was ENP’s general partner. Considering the presumption of control of GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and, therefore, we did not consolidate ENP in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2010.  As presented in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010, “Net income attributable to noncontrolling interest” of $2.1 million and $20.4 million, respectively, represents ENP’s results of operations attributable to third-party ENP limited partner interest owners, other than Denbury, for the portion of that period for which we consolidated ENP.

Net Income Per Common Share

Basic net income per common share is computed by dividing net income attributable to our stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share is calculated in the same manner, but also considers the impact of the potential dilution from stock options, stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and nine months ended September 30, 2011 and 2010, there were no adjustments to net income attributable to our stockholders for purposes of calculating diluted net income per common share.  The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the periods indicated:

 
- 7 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements



 
 
Three Months Ended
   
Nine Months Ended
 
 
 
September 30,
   
September 30,
 
In thousands
 
2011
   
2010
   
2011
   
2010
 
Basic weighted average common shares
    399,040       395,913       398,371       362,241  
Potentially dilutive securities:
                               
Stock options and SARs
    2,954       3,647       3,818       3,772  
Performance equity awards
    41       292       22       305  
Restricted stock
    1,276       1,241       1,364       1,116  
Diluted weighted average common shares
    403,311       401,093       403,575       367,434  

Basic weighted average common shares excludes 3.4 million and 3.5 million shares for the three and nine months ended September 30, 2011, respectively,  and 3.4 million and 3.3 million shares for the three and nine months ended September 30, 2010, respectively, of unvested restricted stock. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share, although all restricted stock is issued and outstanding upon grant.  For purposes of calculating diluted weighted average common shares, unvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share as their effect would have been anti-dilutive:

 
 
Three Months Ended
   
Nine Months Ended
 
 
 
September 30,
   
September 30,
 
In thousands
 
2011
   
2010
   
2011
   
2010
 
Stock options and SARs
    4,731       4,270       3,108       4,613  
Restricted stock
    139       69       56       298  

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 September 30, 2011 and December 31, 2010, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010.  The cost basis of this investment is $93.0 million.  We received distributions of $1.8 million and $5.3 million on the Vanguard common units we own for the three and nine months ended September 30, 2011, respectively, which distributions are included in “Interest income and other income” on our Unaudited Condensed Consolidated Statements of Operations.  The unrealized loss on our short-term investment of $3.9 million (net of a tax benefit of $2.4 million) and $6.9 million (net of a tax benefit of $4.2 million) for the three and nine months ended September 30, 2011, respectively, is included in our Unaudited Condensed Consolidated Statements of Comprehensive Operations.

Recently Issued Accounting Pronouncements
 
In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, Testing Goodwill for Impairment, (“ASU 2011-08”). ASU 2011-08 amends the FASC Intangibles – Goodwill and Other topic by permitting entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in the FASC Intangibles – Goodwill and Other topic.  We adopted ASU 2011-08 and will apply the guidance prospectively to interim and annual goodwill impairment tests.
 
In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either 1) a continuous statement of comprehensive income or 2) two separate but consecutive statements. ASU 2011-05 will be effective for our fiscal year beginning January 1, 2012. Since ASU 2011-05 will only amend presentation requirements, it will not have a material effect on our consolidated financial statements.
 
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 FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will be effective for our fiscal year beginning January 1, 2012. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.
 
 
- 8 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements


Note 2. Acquisitions and Divestitures

Acquisitions

October 2010 and August 2011 Acquisitions of Reserves in Rocky Mountain Region at Riley Ridge

In October 2010, we acquired a 42.5% non-operated working interest in the Riley Ridge Federal Unit (“Riley Ridge”), located in the LaBarge Field of southwestern Wyoming, for $132.3 million after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO2 resources. The purchase included a 42.5% interest in a gas plant, currently under construction, which will separate the helium and natural gas from the commingled gas stream. The acquisition also included approximately 33% of the CO2 mineral rights in an additional 28,000 acres adjoining the Riley Ridge Unit.  The fair values assigned to assets acquired and liabilities assumed in the October 2010 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, 2010.

On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge not already owned, the remaining 57.5% interest in the gas plant and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge. As a result of the transaction, we became the operator of both projects. The purchase price was approximately $214.6 million after preliminary closing adjustments, including a $15 million deferred payment to be made at the time the property’s gas plant is operational and meets specific performance conditions. We expect the gas plant to be operational during the latter part of the first quarter of 2012.

Because the Riley Ridge plant is currently under construction, 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 and 2010.
 
The August 1, 2011 acquisition of Riley Ridge meets the definition of a business under the FASC Business Combinations topic.  The following table presents a summary of the fair value of the Riley Ridge assets acquired and liabilities assumed on August 1, 2011:

In thousands
 
 
 
Consideration:
 
 
 
Cash payment
  $ 199,554  
Deferred payment(1)
    15,000  
Total consideration
    214,554  
 
       
Less:  Fair value of assets and liabilities acquired:(2)
       
Oil and natural gas properties
       
Proved
    48,731  
Unevaluated
    12,542  
CO2 and other non-hydrocarbon gases properties
    9,741  
Pipelines and plants
    91,594  
Other assets(3)
    48,660  
Asset retirement obligations
    (389 )
 
    210,879  
 
       
Goodwill
  $ 3,675  
 
       
(1) The deferred payment is included in "Accounts payable and accrued liabilities" on the accompanying balance sheet and will be paid at the time the property’s gas plant is operational and meets specific performance conditions as described above.  
(2) Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments.  
(3) Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned primarily by the Federal government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the future net revenues associated with the Company’s right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a units-of-production basis.  

 
- 9 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements


2010 Merger with Encore Acquisition Company

On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP (the “Encore Merger”). Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.

For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $174.3 million and $435.2 million, respectively, of oil, natural gas sales and related product sales from properties acquired as part of the Encore Merger.  For the three months ended September 30, 2010 and for the period from March 9, 2010 to September 30, 2010, we recognized $114.1 million and $294.8 million, respectively, of net field operating income (oil, natural gas and related product sales less lease operating expenses, production taxes and marketing expenses) from properties acquired as part of the Encore Merger.  We recognized a total of $11.5 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 September 30, 2010, and $4.4 million and $79.3 million of such costs for the nine months ended September 30, 2011 and 2010, respectively.

Pro Forma Information

Had the Encore Merger occurred on January 1, 2010, our combined pro forma revenues and net income for the three and nine months ended September 30, 2010, would have been as follows:

 
 
Pro Forma Results
 
In thousands, except per share amounts
 
Three Months Ended September 30, 2010
   
Nine Months Ended September 30, 2010
 
Pro forma total revenues
  $ 466,703     $ 1,579,184  
Pro forma net income attributable to Denbury stockholders
    29,104       276,527  
Pro forma net income per common share:
               
Basic
  $ 0.07     $ 0.70  
Diluted
    0.07       0.69  

Divestitures

2010 Sale of Interests in Genesis

In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. (“Genesis”), for net proceeds of approximately $84 million.  In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.

2010 Sales of Non-Strategic Legacy Encore Properties
 
In May 2010, we sold certain non-strategic legacy Encore properties, primarily located in the Permian Basin, the Mid-continent area and the East Texas Basin (the “Southern Assets”), to Quantum Resources Management, LLC for consideration of $892.1 million after closing adjustments.  In August 2010, we sold additional legacy Encore properties, primarily located in the Cleveland Sand Play of western Oklahoma, for consideration of $32.1 million after closing adjustments.  We did not record a gain or loss on the sales in accordance with the full cost method of accounting.
 
 
- 10 -

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:


 
 
September 30,
   
December 31,
 
In thousands
 
2011
   
2010
 
Bank Credit Agreement
  $ 110,000     $ -  
7½% Senior Subordinated Notes due 2013, including discount of $437
    -       224,563  
7½% Senior Subordinated Notes due 2015, including premium of $427
    -       300,427  
9½% Senior Subordinated Notes due 2016, including premium of $12,538 and $14,589, respectively
    237,458       239,509  
9¾% Senior Subordinated Notes due 2016, including discount of $18,925 and $22,139, respectively
    407,425       404,211  
8¼% Senior Subordinated Notes due 2020
    996,273       996,273  
6⅜% Senior Subordinated Notes due 2021
    400,000       -  
Other Subordinated Notes, including premium of $35 and $41, respectively
    3,841       3,848  
NEJD Pipeline financing
    164,626       167,331  
Free State Pipeline financing
    80,093       81,188  
Capital lease obligations
    5,010       6,806  
Total
    2,404,726       2,424,156  
    Less current obligations
    (8,177 )     (7,948 )
Long-term debt and capital lease obligations
  $ 2,396,549     $ 2,416,208  

The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes.  DRI has no independent assets or operations.  Each of the subsidiary guarantors is 100% owned by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the subsidiary guarantors fully and unconditionally guarantee our senior subordinated debt jointly and severally.

Bank Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders as party thereto (the “Bank Credit Agreement”).  Availability under the Bank Credit Agreement is subject to a borrowing base which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations.  The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period of four months.
 
In May 2011, we entered into the Fifth Amendment to the Bank Credit Agreement (the “Fifth Amendment”).  The Fifth Amendment extends the maturity of the Bank Credit Agreement from March 2014 to May 2016, reduces the applicable margin on outstanding borrowings, reduces the letter of credit fee and adjusts the maximum permitted ratio of debt to adjusted EBITDA.  Under the Fifth Amendment, the margin on outstanding Eurodollar loans bears interest at the Eurodollar rate (as defined in the Bank Credit Agreement) plus the applicable margin of 1.5% to 2.5% (previously 2.0% to 3.0%) based on the ratio of outstanding borrowings to the borrowing base, and the base rate loans bear interest at the base rate (as defined in the Bank Credit Agreement) plus the applicable margin of 0.5% to 1.5% (previously 1.0% to 1.5%) based on the ratio of outstanding borrowings to the borrowing base.  The Fifth Amendment also prescribes a commitment fee ranging between 0.375% and 0.5% on the unused portion of the credit facility or if less, the borrowing base, and adjusts the maximum permitted ratio of debt to adjusted EBITDA of Denbury and its subsidiaries from 4.0x to 4.25x.
 
In September 2011, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”).  The Sixth Amendment permits Denbury to make distributions to its equity holders, including specifically repurchase of its common stock and/or making cash dividends with respect thereto, in an aggregate amount of up to $500 million during the term of the Credit Facility, subject to certain restrictions, including pro forma availability of no less than 25% of the borrowing base at the time of any such transactions.  The Sixth Amendment provides us the flexibility to repurchase our common stock and/or pay cash dividends (within the $500 million limit) from time to time as deemed appropriate by, and subject to pre-approval of, our Board of Directors.  Also in September 2011, the banks reaffirmed our borrowing base of $1.6 billion under the Bank Credit Agreement until the next scheduled redetermination in May 2012.

6⅜% Senior Subordinated Notes due 2021

In February 2011, we issued $400 million of 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our outstanding 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes below).

The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2011. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, fully and unconditionally guarantee this debt jointly and severally.
 
 
- 11 -

DENBURY RESOURCES INC.

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 2013 Notes and all $300.0 million principal amount of our 2015 Notes. Upon expiration of the tender offers on March 3, 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par, and $220.9 million in principal of the 2015 Notes at 104.125% of par.  We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011 and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011.  We recognized a $16.1 million loss during the nine months ended September 30, 2011 associated with the debt repurchases, which is included in our Unaudited Condensed Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

Note 4.  Derivative Instruments

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 and commodity price volatility.

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

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

 
 
Three Months Ended
   
Nine Months Ended
 
 
 
September 30,
   
September 30,
 
In thousands
 
2011
   
2010
   
2011
   
2010
 
Oil
 
 
   
 
   
 
   
 
 
Payment on settlements of derivative contracts
  $ 1,857     $ 3,590     $ 23,857     $ 80,969  
Fair value adjustments to derivative contracts - expense (income)
    (205,355 )     62,450       (225,485 )     (144,471 )
Total derivative expense (income) - oil
    (203,498 )     66,040       (201,628 )     (63,502 )
Natural Gas
                               
Receipt on settlements of derivative contracts
    (6,427 )     (13,626 )     (19,073 )     (34,005 )
Fair value adjustments to derivative contracts - expense (income)
    (229 )     (19,933 )     8,393       (39,041 )
Total derivative expense (income) - natural gas
    (6,656 )     (33,559 )     (10,680 )     (73,046 )
Ineffectiveness on interest rate swaps
    -       (627 )     -       (1,497 )
Derivative expense (income)
  $ (210,154 )   $ 31,854     $ (212,308 )   $ (138,045 )

 
- 12 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements



Commodity Derivative Contracts Not Classified as Hedging Instruments

The following tables present outstanding commodity derivative contracts with respect to future production as of September 30, 2011:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX Contract Prices Per Bbl
 
 
 
 
 
 
Type of
 
 
 
Weighted Average Price
Year
 
Months
 
Contract
 
Bbls/d
 
Swap
 
Floor
 
Ceiling
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil Contracts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2011
 
Oct - Dec
 
Swap
 
 625
 
$
 79.18
 
$
 - 
 
$
 - 
 
 
 
 
 
 
Collar
 
 45,500
 
 
 - 
 
 
 70.33
 
 
 101.74
 
 
 
 
 
 
Put
 
 6,625
 
 
 - 
 
 
 69.53
 
 
 - 
 
 
 
 
Total Oct - Dec 2011
 
 52,750
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
Jan - Mar
 
Swap
 
 625
 
 
 81.04
 
 
 - 
 
 
 - 
 
 
 
 
 
 
Collar
 
 52,000
 
 
 - 
 
 
 70.00
 
 
 106.86
 
 
 
 
 
 
Put
 
 625
 
 
 - 
 
 
 65.00
 
 
 - 
 
 
 
 
Total Jan - Mar 2012
 
 53,250
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Apr-June
 
Swap
 
 625
 
 
 81.04
 
 
 - 
 
 
 - 
 
 
 
 
 
 
Collar
 
 53,000
 
 
 - 
 
 
 70.00
 
 
 119.44
 
 
 
 
 
 
Put
 
 625
 
 
 - 
 
 
 65.00
 
 
 - 
 
 
 
 
Total Apr - June 2012
 
 54,250
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
July-Sept
 
Swap
 
 625
 
 
 81.04
 
 
 - 
 
 
 - 
 
 
 
 
 
 
Collar
 
 53,000
 
 
 - 
 
 
 80.00
 
 
 128.57
 
 
 
 
 
 
Put
 
 625
 
 
 - 
 
 
 65.00
 
 
 - 
 
 
 
 
Total July - Sept 2012
 
 54,250
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oct - Dec
 
Swap
 
 625
 
 
 81.04
 
 
 - 
 
 
 - 
 
 
 
 
 
 
Collar
 
 53,000
 
 
 - 
 
 
 80.00
 
 
 128.57
 
 
 
 
 
 
Put
 
 625
 
 
 - 
 
 
 65.00
 
 
 - 
 
 
 
 
Total Oct - Dec 2012
 
 54,250
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
 
Jan - Mar
 
Collar
 
 16,000
 
 
 - 
 
 
 70.00
 
 
 112.66
 
 
 
 
Total Jan - Mar 2013
 
 16,000
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Type of
 
 
 
Weighted Average Swap
Year
 
Months
 
Contract
 
MMBtu/d
 
Price per MMBtu
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas Contracts
 
 
 
 
 
2011
 
Oct - Dec
 
Swap
 
 33,500
 
$
 6.27
 
 
 
 
Total Oct - Dec 2011
 
 33,500
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012
 
Jan - Dec
 
Swap
 
 20,000
 
 
 6.53
 
 
 
 
Total Jan - Dec 2012
 
 20,000
 
 
 

 
- 13 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

 
Additional Disclosures about Derivative Instruments

At September 30, 2011 and December 31, 2010, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

 
 
 
Estimated Fair Value
 
 
 
 
Asset (Liability)
 
In thousands
 
 
September 30,
   
December 31,
 
Type of Contract
Balance Sheet Location
 
2011
   
2010
 
Derivatives not designated as hedging instruments:
 
 
 
   
 
 
Derivative asset
 
 
 
   
 
 
Oil contracts
Derivative assets - current
  $ 96,177     $ 3,050  
Natural gas contracts
Derivative assets - current
    20,584       21,192  
Oil contracts
Derivative assets - long-term
    52,627       1,301  
Natural gas contracts
Derivative assets - long-term
    3,833       11,618  
 
 
               
Derivative liability
 
               
Oil contracts
Derivative liabilities - current
    (60 )     (55,256 )
Deferred premiums
Derivative liabilities - current
    (9,193 )     (22,928 )
Oil contracts
Derivative liabilities - long-term
    (70 )     (25,906 )
Deferred premiums
Derivative liabilities - long-term
    (662 )     (3,781 )
Total derivatives not designated as hedging instruments
 
  $ 163,236     $ (70,710 )

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. 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 (e.g., Houston Ship Channel).

We adjust the valuations for nonperformance risk, using our estimate of the counterparty's credit quality for asset positions and Denbury's credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
 
 
- 14 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements


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
 
September 30, 2011
 
 
 
Assets
 
 
   
 
   
 
   
 
 
Short-term investments
  $ 81,851     $ -     $ -     $ 81,851  
Oil and natural gas derivative contracts
    -       166,244       6,977       173,221  
Liabilities
                               
Oil and natural gas derivative contracts
    -       (130 )     -       (130 )
Total
  $ 81,851     $ 166,114     $ 6,977     $ 254,942  
 
                               
December 31, 2010
                               
Assets
                               
Short-term investments
  $ 93,020     $ -     $ -     $ 93,020  
Oil and natural gas derivative contracts
    -       20,683       16,478       37,161  
Liabilities
                               
Oil and natural gas derivative contracts
    -       (81,162 )     -       (81,162 )
Total
  $ 93,020     $ (60,479 )   $ 16,478     $ 49,019  

The following table summarizes the changes in the fair value of our Level 3 assets for the three and nine months ended September 30, 2011 and 2010:

 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
In thousands
2011
 
2010
 
2011
 
2010
 
Balance, beginning of period
  $ 6,638     $ 40,283     $ 16,478     $ -  
Unrealized gains (losses) on commodity derivative contracts included in earnings
    1,717       20,103       (5,359 )     35,002  
Commodity derivative contracts acquired from Encore
    -       -       -       38,093  
Receipts on settlement of commodity derivative contracts
    (1,378 )     (9,035 )     (4,142 )     (21,744 )
Balance, end of period
  $ 6,977     $ 51,351     $ 6,977     $ 51,351  

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.

 
- 15 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements



The following table sets forth the fair value of financial instruments that are not recorded at fair value in our Unaudited Condensed Consolidated Financial Statements.  See Note 3, Long-Term Debt and Item 3, Quantitative and Qualitative Disclosures about Market Risk for further information about these financial instruments.

 
 
September 30, 2011
   
December 31, 2010
 
 
 
Carrying
   
Estimated
   
Carrying
   
Estimated
 
In thousands
 
Amount
   
Fair Value
   
Amount
   
Fair Value
 
7½% Senior Subordinated Notes due 2013
  $ -     $ -     $ 224,563     $ 228,375  
7½% Senior Subordinated Notes due 2015
    -       -       300,427       310,500  
9½% Senior Subordinated Notes due 2016
    237,458       242,914       239,509       249,661  
9¾% Senior Subordinated Notes due 2016
    407,425       460,458       404,211       475,380  
8¼% Senior Subordinated Notes due 2020
    996,273       1,046,087       996,273       1,080,956  
6⅜% Senior Subordinated Notes due 2021
    400,000       388,000       -       -  

The fair values of our senior subordinated notes are based on quoted market prices.  We have other financial instruments consisting primarily of cash, cash equivalents, our Bank Credit Agreement, and short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 6.  Supplemental Information

Accounts Payable and Accrued Liabilities

The following table summarizes our accounts payable and accrued liabilities as of the periods indicated:

 
 
September 30,
   
December 31,
 
In thousands
 
2011
   
2010
 
Accounts payable
  $ 107,391     $ 47,660  
Accrued exploration and development costs
    143,647       101,758  
Accrued compensation
    27,476       39,757  
Accrued lease operating expense
    30,005       23,557  
Accrued interest
    28,957       57,077  
Taxes payable
    19,214       34,371  
Deferred Riley Ridge acquisition consideration
    15,000       -  
Other
    33,553       45,888  
Total
  $ 405,243     $ 350,068  

Supplemental Cash Flow Information

The following table sets forth supplemental cash flow information for the periods indicated:

 
 
Nine Months Ended
 
 
 
September 30,
 
In thousands
 
2011
 
2010
 
Cash paid for interest, expensed
  $ 137,289     $ 114,012  
Cash paid for interest, capitalized
    42,004       56,079  
Cash paid for income taxes
    36,688       13,691  
Cash received for income tax refunds
    21,990       13,525  
Increase in liabilities for capital expenditures
    86,769       13,880  
Issuance of Denbury common stock in connection with the Encore Merger
    -       2,085,681  
 
 
- 16 -

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

 
Note 7. Commitments and Contingencies

In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions.  The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions.  Under the three new contracts, Denbury will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC's Medicine Bow Fuel and Power LLC ("MBFP") project near Medicine Bow, Wyoming, purchase 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("Mississippi Power") project in Mississippi, and purchase 100% of the CO2 captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas.  These new contracts each have an initial term of 15 to 16 years and include options to extend the term. We estimate that these new sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf.  We expect to begin taking delivery of approximately 100 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the Mississippi Power project by 2014, and 50 MMcf/d of CO2 from Air Products in late 2012.  Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price.  The purchase price of CO2 will fluctuate based on the changes in the price of oil. 

As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies.  The Mississippi Power and Air Products plants are currently being constructed, and the MBFP project is contingent upon securing debt financing, equity commitments and receipt of all necessary consents and approvals.
 
In conjunction with the August 1, 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third party purchaser.  Subsequently, we amended this contract to provide for annual delivery (to the 8/8ths working interest) of 127 MMcf of helium (previously 200 MMcf) during the first two years of the contract and thereafter provides for delivery of 400 MMcf of helium per year.  If the contracted quantity of helium is not supplied, we are obligated to compensate the third party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year.
 
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.  Currently, we have no material assessments for potential taxes.

 We are involved in various lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs.  We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Note 8. Subsequent Event

In early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company’s Board of Directors.  The program has no pre-established ending date, and may be suspended or discontinued at any time.  The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.  Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for $149.3 million, or $13.58 per share under this share repurchase program.

 
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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 Part II of this report, along with Forward-Looking Information at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are a growing independent oil and natural gas company. We are the largest oil and natural gas producer in both Mississippi and Montana, own the largest CO2 reserves used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO2 tertiary recovery operations.

The acquisition of Encore Acquisition Company (the “Encore Merger”) on March 9, 2010, has had a significant impact on nearly every aspect of our business, including oil and natural gas production, revenues and operating expenses.  Accordingly, the Encore Merger impacts the comparability of our financial results from the first nine months of 2010 to those in the first nine months of 2011, which is more fully detailed throughout the following discussion and analysis.  Our financial results for the first nine months of 2010 include the results of operations of Encore from the date of the acquisition on March 9, 2010 through September 30, 2010.  Additionally, starting in May 2010 and throughout the remainder of 2010, we disposed of non-strategic Encore properties and our ownership interests in Encore Energy Partners LP (“ENP”).

Third Quarter Operating Highlights

We recognized net income of $275.7 million, or $0.69 per basic common share, during the third quarter of 2011 as compared to net income of $29.1 million, or $0.07 per basic common share, during the third quarter of 2010.  This increase between the two periods is primarily attributable to:

·  
incremental income of $248.1 million ($153.8 million after tax) attributable to the non-cash increase in the fair value of the Company’s commodity derivative contracts, principally due to the change in NYMEX oil futures prices; and

·  
an increase in revenue of $104.7 million ($64.9 million after tax), or 23%, as a result of higher commodity prices, partially offset by lower production as a result of asset sales in late 2010.

During the third quarter of 2011, our oil and natural gas production, which was 93% oil, averaged 66,830 BOE/d as compared to 77,730 BOE/d produced during the third quarter of 2010.  This drop in production is primarily attributable to the fourth quarter of 2010 sale of our Haynesville natural gas assets and our interests in ENP.  After adjusting third quarter 2010 production to exclude production from properties which were sold in the fourth quarter of 2010, continuing production in the third quarter of 2011 increased 6% over production in the comparable prior year quarter.  This production increase was primarily attributable to increases in our Bakken and tertiary oil production in the most recent quarter.  Our tertiary oil production averaged 31,091 Bbls/d during the third quarter of 2011, up 5% over the 29,531 Bbls/d produced during the third quarter a year earlier and up 1%, or 320 Bbls/d, over second quarter 2011 levels.  Our Bakken oil production averaged 9,976 BOE/d during the third quarter of 2011, an increase of 114% over production of 4,657 BOE/d during the third quarter of 2010 and sequentially up 2,350 BOE/d or 31% from levels in the second quarter of 2011.  See Results of Operations — CO2 Operations and Results of Operations — Operating Results — Production for more information.

Oil prices received during the third quarter of 2011 were considerably higher than prices received during the third quarter of 2010.  Our average oil and natural gas price received per BOE, excluding the impact of commodity derivative contracts, was $91.98 per BOE during the third quarter of 2011, compared to $64.44 per BOE during the third quarter of 2010, a 43% increase between the comparative third quarter periods.  During the third quarter of 2011, our oil price differentials (our received net oil price compared to NYMEX West Texas Intermediate (“WTI”) prices) improved by $11.10 per Bbl, from a negative $3.85 per Bbl in the third quarter of 2010 to a positive $7.25 per Bbl in the third quarter of 2011, primarily due to the favorable price differential for our crude oil sold under Louisiana Light Sweet (“LLS”) index pricing.  See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information.

August 2011 Acquisition of Remaining Working Interest in Riley Ridge

On August 1, 2011, we acquired the remaining 57.5% working interest that we did not already own in the Riley Ridge Federal Unit (“Riley Ridge”), the remaining 57.5% interest in the gas plant and a working interest of approximately 33% in the 28,000 acres adjacent to Riley Ridge.  As a result of the transaction, we became the operator of both projects.  The purchase price after preliminary closing adjustments was approximately $214.6 million, which includes a $15 million deferred payment to be made at the time the property’s gas plant is operational and meets specific performance conditions.  We currently expect the gas plant to be operational with the first production of natural gas and helium from Riley Ridge during the latter part of the first quarter of 2012.  The CO2will be re-injected into the reservoir until we have completed an additional separation facility and a CO2pipeline to the field, which is expected to be completed in 2016.

Combining this acquisition with the interests in Riley Ridge that we acquired in October 2010, we estimate that, as of September 30, 2011, our total ownership at Riley Ridge contains estimated proved reserves of 431 Bcf of natural gas, 15.3 Bcf of helium and 2.2 Tcf of CO2.  The adjacent 28,000 acres is estimated to contain additional probable reserves of 250 to 300 Bcf of natural gas, 9.5 to 11.5 Bcf of helium and 2.0 to 2.2 Tcf of CO2, net to our interest.  These estimates of potential reserves, which include estimates of probable reserves based on the most recent drilling and technical data available, are more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering these reserves is subject to substantially greater risk.
 
 
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DENBURY RESOURCES INC.

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


Addition of Proved Oil and Natural Gas Reserves

We added 83.0 MMBOE of estimated proved reserves during the first nine months of 2011, including 52.1 MMBOE of estimated proved reserves during the third quarter of 2011.  The third quarter 2011 reserve additions include 237 Bcf  (39.5 MMBOE) in fields in the Riley Ridge acquisition completed in August, which is discussed above, 11.6 MMBOE in our Bakken properties, and minor revisions to our other properties.

Recent Common Share Repurchase Program

In early October 2011, we announced the commencement of a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company’s Board of Directors.  The program has no pre-established ending date, and may be suspended or discontinued at any time.  The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.  Between early October 2011 and October 31, 2011, we repurchased 10,990,939 shares of Denbury common stock (approximately 2.7% of our outstanding shares of common stock at September 30, 2011) for $149.3 million, or $13.58 per share under this share repurchase program.

March 2011 CO2 Purchase Contracts

In March 2011, we entered into three long-term supply contracts to purchase CO2 from future anthropogenic sources in the Gulf Coast and Rocky Mountain regions.  The three contracts are in addition to the previously disclosed long-term supply contracts Denbury currently has in place in the Gulf Coast, Rocky Mountain and Midwest regions.  We will purchase 100% of the CO2 captured from the DKRW Advanced Fuels LLC's Medicine Bow Fuel and Power LLC project ("MBFP") near Medicine Bow, Wyoming, 70% of the CO2 captured from Mississippi Power Company's Kemper County Integrated Gasification Combined Cycle ("Mississippi Power") project in Mississippi, and 100% of the CO2captured by Air Products LLC (“Air Products”) at a third-party refinery in Port Arthur, Texas.  These three contracts each have an initial term of 15 to 16 years and include options to extend the term.  We estimate these three sources will supply approximately 365 MMcf/d of CO2 for our enhanced oil recovery operations, although under certain circumstances, we may be obligated to purchase up to 460 MMcf/d, a portion of which would be at a reduced price per Mcf.  We expect to begin taking delivery of approximately 100 MMCF/d of CO2 from the MBFP project in 2015, 115 MMcf/d of CO2 from the Mississippi Power project in 2014, and 50 MMcf/d of CO2 from Air Products in late 2012.  Our aggregate maximum purchase obligation for CO2 purchased under these three contracts would be approximately $110 million per year (assuming purchases of 460 MMcf/d), plus transportation, assuming a $100 per barrel NYMEX oil price.  The purchase price of CO2 will fluctuate based on the changes in the price of oil.

As is the case with all of our long-term supply contracts to purchase CO2, the three agreements entered into in March are subject to various contingencies.  The Mississippi Power and Air Products plants are currently being constructed, and the MBFP project is contingent upon securing debt financing, equity commitments and receipt of all necessary consents and approvals.

February 2011 Senior Notes Refinancing

In February 2011, we issued, at par, $400 million of 6⅜% Senior Subordinated Notes due 2021. The net proceeds, together with cash on hand, were used to partially fund the repurchase of $525 million in principal amount of our outstanding 2013 Notes and 2015 Notes in cash tender offers to purchase $225 million principal amount of our 2013 Notes and $300 million principal amount of our 2015 Notes.  In the first quarter of 2011, we accepted for purchase $169.6 million in principal of the 2013 Notes at 100.625% of par and $220.9 million in principal of the 2015 Notes at 104.125% of par.  We redeemed the remaining outstanding 2015 Notes at 103.75% of par during the first quarter of 2011 and all of the remaining outstanding 2013 Notes at par on April 1, 2011.  During the nine months ended September 30, 2011, we recognized $16.1 million of loss associated with the debt repurchases, included in our income statements under the caption “Loss on early extinguishment of debt”.
 
 
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DENBURY RESOURCES INC.

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

Capital Resources and Liquidity

We currently project that our 2011 oil and gas capital investments will be $1.35 billion, excluding capitalized interest, tertiary start-up costs, acquisitions and divestitures, and net of equipment leases.

Our current 2011 capital budget includes the following:

·  
$475 million allocated for tertiary oil field expenditures;
·  
$400 million in the Bakken area of North Dakota;
·  
$200 million to be spent on our CO2 pipelines;
·  
$200 million to be spent on CO2 sources in the Jackson Dome and Riley Ridge areas; and
·  
$75 million on drilling, completion and other development activities in our other areas.

During the first nine months of 2011, we have incurred expenditures of approximately $1 billion associated with our capital budget, net of equipment lease recoveries of $43 million.  Additionally, we have capitalized interest of $42.0 million and tertiary start-up costs related to Hastings and Oyster Bayou Fields of $23 million, which are not included in the above mentioned capital budget.  See additional detail on our expenditures below.

Based on oil and natural gas commodity futures prices in early November 2011 and our current production forecasts, excluding acquisition costs, our 2011 capital budget, including capitalized interest and tertiary start-up costs, is expected to be $150 million to $250 million greater than our 2011 anticipated cash flow from operations.  This shortfall is expected to be funded with cash on hand (which was $381.9 million at December 31, 2010), and borrowings under our $1.6 billion bank credit facility.  Additionally, the future sale of our investment in Vanguard Natural Resources LLP units acquired in the sale of ENP, which have ranged in value between approximately $80 million and $95 million during the third quarter of 2011, could serve as another source of proceeds to fund our capital spending.  At October 31, 2011, we had drawn $350 million under our Bank Credit Facility, which was used in part to fund our August 1, 2011 Riley Ridge acquisition discussed above and in part to fund our share repurchase program discussed above.

As discussed above, in October 2011 we announced a common share repurchase program for up to $500 million of Denbury shares.  We plan to fund our share repurchase program in the near term through borrowings on our Bank Credit Facility and in the longer term by reducing our 2012 capital investments and/or by using proceeds from planned asset sales of miscellaneous minor properties.  As it is difficult to forecast future commodity prices, the number of shares repurchased and proceeds from asset sales, we may need to adjust our 2012 plans throughout the year as our goal is to keep any incremental debt related to these combined activities to approximately $250 million or less.   See details regarding our share repurchases above.

We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could impact the timing of our future production.  There are potential limitations on the amount of capital spending we can eliminate without penalties (refer to Management’s Discussion and Analysis – Capital Resources and Liquidity - Off-Balance Sheet Arrangements — Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010, and see CO2 Purchase Contracts above and Off-Balance Sheet Arrangements below for further information regarding additional commitments entered into during 2011).  In addition to the potential flexibility in our capital spending plans, as of October 31, 2011, we had approximately $1.25 billion of unused liquidity under our bank credit facility and have oil price floors through the first quarter of 2013 (see Note 4 to the Unaudited Condensed Consolidated Financial Statements), which together should provide us with adequate liquidity and flexibility to meet our near-term capital spending plans if oil prices were to decrease significantly. 

Our capital spending estimate also assumes that we fund approximately $60 million of budgeted equipment purchases with operating leases, the amount of which is dependent upon securing acceptable financing.  Through September 30, 2011, we have funded approximately $43 million of these budgeted equipment purchases with operating leases.  Our net capital expenditures would increase by the amount of any shortfall in operating leases for this purchased equipment, and we anticipate funding any such additional capital expenditures under our Bank Credit Agreement.
 
In September 2011, we entered into our Sixth Amendment to the Bank Credit Agreement, enabling us to make certain distributions to our equity holders, including repurchase our common stock and/or make cash dividends on such common stock, in an aggregate amount of up to $500 million.  Also in September 2011, the banks reaffirmed our borrowing base of $1.6 billion under the Bank Credit Agreement.  See further discussion in Note 3 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

Capital Expenditure Summary

The following table of capital expenditures includes accrued capital for the nine months ended September 30, 2011 and 2010:

   
Nine Months Ended
 
   
September 30,
 
In thousands
 
2011
   
2010
 
Oil and natural gas exploration and development:
 
 
   
 
 
Drilling
  $ 399,812     $ 242,302  
Geological, geophysical, and acreage
    26,609       23,381  
Facilities
    195,928       99,797  
Recompletions
    177,569       136,357  
Capitalized interest
    31,116       23,672  
Total oil and natural gas exploration and development expenditures
    831,034       525,509  
CO2 and other non-hydrocarbon gases capital expenditures:
               
Drilling
    47,750       29,222  
Geological, geophysical, and acreage
    9,314       17,341  
Facilities
    24,926       20,291  
Total CO2 and other non-hydrocarbon gases capital expenditures
    81,990       66,854  
Pipelines and plants capital expenditures:
               
Pipelines and plants
    114,024       138,511  
Capitalized interest
    10,888       32,407  
Total pipelines and plants capital expenditures
    124,912       170,918  
Total capital expenditures excluding acquisitions
    1,037,936       763,281  
Oil and natural gas property acquisitions
    34,291       24,390  
Consideration for the Encore Merger(1)
    -       2,952,515  
Consideration for August 2011 Riley Ridge acquisition
    214,554       -  
Total
  $ 1,286,781     $ 3,740,186  

(1) Consideration given in the Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued.

Our capital expenditures, excluding the Riley Ridge acquisition, for the first nine months of 2011 were funded with $839.1 million of cash flow from operations, and cash on hand at the beginning of the period. Our capital expenditures for the first nine months of 2010, excluding the Encore Merger, were funded with $592.8 million of cash flow from operations together with proceeds from the sales of our interests in Genesis Energy, L.P. (“Genesis”) and non-strategic legacy Encore properties sold during May 2010 (the “Southern Assets”).

Off-Balance Sheet Arrangements

Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry.  In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in our proved reserve reports.  Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Notes 4 and 5 to the Unaudited Condensed Consolidated Financial Statements.

In April 2011, we entered into three long-term drilling contracts.  Our total commitment under these contracts is approximately $91 million, with $7 million expected to be paid during the remainder of 2011, $31 million in both 2012 and 2013, and $22 million in 2014.

In May 2011, we entered into an agreement with Elk Petroleum to acquire a 65% working interest in Grieve Field, a planned CO2 enhanced oil recovery project located in Wyoming.  Denbury will invest the first $28.5 million of capital and operating costs in Phase 1.  In Phase 2 of the project, Denbury may fund, at Elk’s option, Elk’s 35% share of the next $34.3 million of capital and operating costs, with Denbury recouping its Phase 2 expenditures (plus interest) out of Elk’s 35% working interest share of production from the project.  In connection with that agreement, we were assigned a CO2 purchase and CO2 transportation contract to purchase CO2 reserves from Exxon Mobil Corporation’s La Barge facility and transport the CO2 to Grieve Field beginning in March of 2012.  Our annual commitment under the CO2 purchase and transportation contracts is approximately $16 million annually for 2 years and approximately $25 million annually for the remaining 8 years (assuming a $100 per barrel NYMEX oil price).      

Our commitments and obligations consist of those detailed as of December 31, 2010 in our 2010 Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations - Off-Balance Sheet Arrangements – Commitments and Obligations, plus the long-term drilling contracts described above, the Grieve Field obligations detailed above, and the three CO2 purchase contracts entered into during the first quarter of 2011, which CO2 purchase contracts are subject to numerous contingencies, as discussed under Overview – CO2 Purchase Contracts above.
 
 
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DENBURY RESOURCES INC.

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

 
Results of Operations

CO2 Operations

Our focus on CO2 operations is 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 third quarter of 2011, our CO2 production at Jackson Dome averaged 1,001 MMcf/d, compared to an average of 864 MMcf/d produced during the third quarter of 2010 and 992 MMcf/d produced during the second quarter of 2011.  We used 90% of this production, or 903 MMcf/d, in our tertiary operations during the third quarter of 2011, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.  Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Off-Balance Sheet Arrangements – Commitments and Obligations in our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion on our CO2 delivery obligations.  We recognized a negative proven CO2 reserve revision during the second quarter of approximately 239 Bcf at our Jackson Dome Dri-Dock prospect.  This revision was a result of the second well in this formation not being a productive well and analysis of the reprocessed seismic data, which showed incremental faulting in the Dri-Dock reservoir.  During October, 2011, we completed another well in the Gluckstadt prospect.  We estimate that this well added approximately 313 Bcf of additional proven CO2 reserves.  After adjusting for these changes, we believe that we have sufficient CO2 reserves to develop our current Gulf Coast enhanced oil recovery program and we are continuing to drill additional wells to increase our productive capability and to test the significant probable and possible reserves at Jackson Dome.  At December 31, 2010, our proven CO2 reserves at Jackson Dome were approximately 7.1 Tcf.

During the fourth quarter of 2011 we commenced drilling an exploratory well at Jackson Dome.  Because we have not established proved or probable reserves in the drilling area, in accordance with our accounting policy for CO2 properties, we expect to expense between $9 million and $12 million of drilling costs during the fourth quarter of 2011, which will be classified as “CO2 discovery and operating expenses” on our Statement of Operations.

We spent approximately $0.26 per Mcf in operating expenses to produce our CO2 during the first nine months of 2011, which costs averaged $0.25 per Mcf during the first quarter of 2011, $0.28 per Mcf during the second quarter of 2011, and $0.24 per Mcf during the third quarter of 2011.  This rate is up significantly from our $0.21 per Mcf cost during the third quarter of 2010, due primarily to increased CO2 royalty expense as a result of higher oil prices (to which CO2 royalties are tied).

The following table summarizes our tertiary oil production and tertiary lease operating expense per Bbl for each quarter in 2010 and the first, second, and third quarters of 2011:

 
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DENBURY RESOURCES INC.

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



 
 
Average Daily Production (Bbls/d)
 
 
 
First
   
Second
   
Third
   
Fourth
   
First
   
Second
   
Third
 
 
 
Quarter
   
Quarter
   
Quarter
   
Quarter
   
Quarter
   
Quarter
   
Quarter
 
Tertiary Oil Field
 
2010
   
2010
   
2010
   
2010
   
2011
   
2011
   
2011
 
Phase 1:
 
 
   
 
   
 
   
 
   
 
   
 
   
 
 
Brookhaven
    3,416       3,277       3,323       3,699       3,664       3,213       3,030  
McComb area
    2,289       2,160       2,484       2,433       2,161       1,983       2,005  
Mallalieu area
    3,443       3,628       3,279       3,164       2,925       2,646       2,620  
Other
    2,817       3,282       3,343       3,361       3,290       3,196       2,879  
Phase 2:
                                                       
Heidelberg
    1,708       1,857       2,806       3,422       3,374       3,548       3,141  
Eucutta
    3,792       3,625       3,284       3,286       3,247       3,114       2,985  
Soso
    3,213       3,207       3,016       2,828       2,582       2,317       2,331  
Martinville
    927       764       606       586       500       416       453  
Phase 3:
                                                       
Tinsley
    4,419       5,248       6,024       6,614       6,567       6,990       7,075  
Phase 4:
                                                       
Cranfield
    936       811       855       1,043       991       1,085       1,214  
Phase 5: