Denbury (DNRWW) 10-Q 2010 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010

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	(I.R.S. Employer
incorporation or organization)	Identification No.)
5100 Tennyson Parkway
Suite 1200
Plano, TX	75024
(Address of principal executive offices)	(Zip Code)

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

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. Yesþ Noo

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). Yesþ Noo

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 filerþ  Accelerated filero  Non-accelerated filero
(Do not check if a smaller reporting company) Smaller reporting companyo 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

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 July 31, 2010
Common Stock, $.001 par value	399,274,000

DENBURY RESOURCES INC.

INDEX

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009		4
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009		5
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009		6
Unaudited Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2010		7
Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 30, 2010 and 2009		8
Notes to Unaudited Condensed Consolidated Financial Statements		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 3. Quantitative and Qualitative Disclosures about Market Risk		55
Item 4. Controls and Procedures		56
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		58
Item 1A. Risk Factors		58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		58
Item 6. Exhibits		58
Signatures		60
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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DENBURY RESOURCES INC.

GLOSSARY AND SELECT ABBREVIATIONS

     The following are abbreviations and definitions of certain terms used in this report. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been summarized from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Bbl	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d	Barrels of oil produced per day.
Bcf/d	One billion cubic feet of natural gas or CO2 produced per day.
BOE	One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate, or natural gas liquids to six Mcf of natural gas.
BOE/d	BOEs produced per day.
CO2	Carbon dioxide.
Denbury	Denbury Resources Inc., a publicly traded Delaware corporation, together with its subsidiaries.
Encore	Encore Acquisition Company, together with its subsidiaries. Encore merged with and into Denbury on March 9, 2010.
ENP	Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
EOR	Enhanced oil recovery.
FASB	Financial Accounting Standards Board.
FASC	FASB Accounting Standards Codification.
LIBOR	London Interbank Offered Rate.
MBOE	One thousand BOEs.
Mcf	One thousand cubic feet of natural gas or CO2.
Mcf/d	One thousand cubic feet of natural gas or CO2 produced per day.
MMBOE	One million BOEs.
MMcf/d	One million cubic feet of natural gas or CO2 per day.
NYMEX	New York Mercantile Exchange.
Proved Developed Reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves	The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
SEC	The United States Securities and Exchange Commission.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except par value and share data)

	June 30,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	67,474		$	20,591
Accrued production receivable		193,086			120,667
Trade and other receivables, net of allowance of $449 and $414, respectively		120,100			67,874
Derivatives		77,294			309
Deferred taxes		—			46,321
Total current assets		457,954			255,762
Property and equipment:
Oil and natural gas properties (using full cost accounting):
Proved		6,834,676			3,595,726
Unevaluated		1,185,627			320,356
CO2 properties, equipment, and pipelines		1,704,700			1,529,781
Other		100,751			82,537
Less accumulated depletion, depreciation, amortization, and impairment		(2,033,936	)		(1,825,528	)
Net property and equipment		7,791,818			3,702,872
Derivatives		54,855			506
Goodwill		1,220,172			169,517
Other		221,038			141,321
Total assets	$	9,745,837		$	4,269,978
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	360,058		$	169,874
Oil and natural gas production payable		151,333			90,218
Derivatives		43,943			124,320
Deferred taxes		21,883			—
Current maturities of long-term debt		7,464			5,308
Other		4,070			4,070
Total current liabilities		588,751			393,790
Long-term liabilities:
Long-term debt, net of current portion		2,704,405			1,301,068
Asset retirement obligations, net of current portion		91,742			53,251
Deferred taxes		1,483,371			515,516
Derivatives		19,582			5,239
Other		26,508			28,877
Total long-term liabilities		4,325,608			1,903,951
Commitments and contingencies (Note 10)
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; 399,570,878 and 261,929,292 shares issued, respectively		400			262
Paid-in capital in excess of par		3,017,576			910,540
Retained earnings		1,296,674			1,064,419
Accumulated other comprehensive loss		(567	)		(557	)
Treasury stock, at cost, 240,396 and 156,284 shares, respectively		(3,842	)		(2,427	)
Total Denbury stockholders’ equity		4,310,241			1,972,237
Noncontrolling interest		521,237			—
Total equity		4,831,478			1,972,237
Total liabilities and equity	$	9,745,837		$	4,269,978

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues and other income:
Oil, natural gas, and related product sales	$	488,028		$	211,552		$	818,914		$	379,621
CO2 sales and transportation fees		4,690			2,884			9,187			6,049
Gain on sale of interests in Genesis		(28	)		—			101,540			—
Interest income and other		4,520			2,956			6,390			5,481
Total revenues		497,210			217,392			936,031			391,151
Expenses:
Lease operating expenses		127,743			83,658			223,963			158,608
Production taxes and marketing expenses		38,100			10,784			57,417			19,976
CO2 operating expenses		1,681			1,095			3,049			2,395
General and administrative		31,192			33,135			63,901			55,790
Interest, net of amounts capitalized of $23,850, $15,454, $45,162, and $27,827, respectively		43,483			14,904			69,899			27,101
Depletion, depreciation, and amortization		129,209			61,695			211,081			123,620
Derivatives expense (income)		(128,674	)		152,789			(169,899	)		173,304
Transaction costs related to the Encore Merger		22,784			—			67,783			—
Total expenses		265,518			358,060			527,194			560,794
Income (loss) before income taxes		231,692			(140,668	)		408,837			(169,643	)
Income tax provision (benefit):
Current income taxes		6,941			24,127			7,610			24,300
Deferred income taxes		74,422			(77,555	)		150,694			(88,406	)
Consolidated net income (loss)		150,329			(87,240	)		250,533			(105,537	)
Less: net income attributable to noncontrolling interest		(14,962	)		—			(18,278	)		—
Net income (loss) attributable to Denbury stockholders	$	135,367		$	(87,240	)	$	232,255		$	(105,537	)
Net income (loss) per common share:
Basic	$	0.34		$	(0.35	)	$	0.67		$	(0.43	)
Diluted	$	0.34		$	(0.35	)	$	0.66		$	(0.43	)
Weighted average common shares outstanding:
Basic		395,548			246,084			345,126			245,830
Diluted		400,867			246,084			350,326			245,830

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:
Consolidated net income (loss)	$	250,533		$	(105,537	)
Adjustments needed to reconcile consolidated net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		211,081			123,620
Deferred income taxes		150,694			(88,406	)
Gain on sale of interests in Genesis		(101,540	)		—
Stock-based compensation		17,130			16,566
Non-cash fair value derivative adjustments		(226,899	)		301,197
Founder’s retirement compensation		—			6,350
Other		5,871			(2,426	)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accrued production receivable		52,075			(33,520	)
Trade and other receivables		10,058			18,897
Other assets		(3,134	)		(21	)
Accounts payable and accrued liabilities		12,066			33,026
Oil and natural gas production payable		11,236			(9,574	)
Other liabilities		(4,880	)		617
Net cash provided by operating activities		384,291			260,789
Cash flows used for investing activities:
Oil and natural gas capital expenditures		(317,173	)		(215,978	)
Acquisitions of oil and natural gas properties		(24,243	)		(196,274	)
Cash paid in Encore Merger, net of cash acquired		(801,489	)		—
CO2 capital expenditures, including pipelines		(152,451	)		(399,406	)
Net proceeds from sales of oil and natural gas properties and equipment		881,344			240,087
Net proceeds from sale of interests in Genesis		162,622			—
Other		(7,224	)		(3,269	)
Net cash used for investing activities		(258,614	)		(574,840	)
Cash flows from financing activities:
Bank repayments		(1,514,000	)		(505,000	)
Bank borrowings		1,149,000			475,000
Senior subordinated notes tendered post Encore Merger		(616,638	)		—
Net proceeds from issuance of senior subordinated debt		1,000,000			389,827
Net proceeds from issuance of common stock		5,540			7,257
Costs of debt financing		(76,232	)		(10,080	)
ENP distributions		(12,209	)		—
Other		(14,255	)		(63	)
Net cash provided by (used for) financing activities		(78,794	)		356,941
Net increase in cash and cash equivalents		46,883			42,890
Cash and cash equivalents at beginning of period		20,591			17,069
Cash and cash equivalents at end of period	$	67,474		$	59,959

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands, except share data)

	Denbury Stockholders
						Paid-In				Accumulated									Total
	Common Stock					Capital in				Other			Treasury Stock						Denbury
	($.001 Par Value)					Excess of		Retained		Comprehensive			(at cost)						Stockholders’			Noncontrolling			Total
	Shares			Amount		Par		Earnings		Loss			Shares			Amount			Equity			Interest			Equity
Balance — December 31, 2009		261,929,292		$	262	$	910,540	$	1,064,419	$	(557	)		156,284		$	(2,427	)	$	1,972,237		$	—		$	1,972,237
Repurchase of common stock		—			—		—		—		—			330,122			(5,327	)		(5,327	)		—			(5,327	)
Issued pursuant to employee stock purchase plan		—			—		—		—		—			(246,010	)		3,912			3,912			—			3,912
Issued pursuant to employee stock option plan		278,141			—		1,595		—		—			—			—			1,595			—			1,595
Issued pursuant to directors’ compensation plan		7,960			—		125		—		—			—			—			125			—			125
Issued pursuant to Encore Merger		135,170,505			135		2,085,546		—		—			—			—			2,085,681			—			2,085,681
Restricted stock grants		1,908,450			2		—		—		—			—			—			2			—			2
Restricted stock grants — forfeited		(169,963	)		—		—		—		—			—			—			—			—			—
Performance-based shares issued		446,493			1		—		—		—			—			—			1			—			1
Stock-based compensation		—			—		19,701		—		—			—			—			19,701			—			19,701
Income tax benefit from equity awards		—			—		69		—		—			—			—			69			—			69
ENP revaluation at Encore Merger		—			—		—		—		—			—			—			—			515,210			515,210
ENP cash distributions to noncontrolling interest		—			—		—		—		—			—			—			—			(12,208	)		(12,208	)
Derivative contracts, net		—			—		—		—		(10	)		—			—			(10	)		(43	)		(53	)
Consolidated net income		—			—		—		232,255		—			—			—			232,255			18,278			250,533
Balance — June 30, 2010		399,570,878		$	400	$	3,017,576	$	1,296,674	$	(567	)		240,396		$	(3,842	)	$	4,310,241		$	521,237		$	4,831,478

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Consolidated net income (loss)	$	150,329		$	(87,240	)	$	250,533		$	(105,537	)
Other comprehensive income (loss), net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $10, $10, $21, and $21, respectively		17			17			34			35
Change in deferred hedge loss on interest rate swaps, net of tax of $8, $0, $18, and $0, respectively		(60	)		—			(87	)		—
Consolidated comprehensive income (loss)		150,286			(87,223	)		250,480			(105,502	)
Less: comprehensive income attributable to noncontrolling interest		(14,950	)		—			(18,235	)		—
Comprehensive income (loss) attributable to Denbury stockholders	$	135,336		$	(87,223	)	$	232,245		$	(105,502	)

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Description of Business

Organization and Nature of Operations

     Denbury is a growing independent oil and natural gas company. Denbury is the largest oil and natural gas operator in both Mississippi and Montana, owns the largest reserves of CO₂ used for tertiary oil recovery east of the Mississippi River, and holds significant operating acreage in the Rockies, Permian Basin, and Gulf Coast regions. Denbury’s goal is to increase the value of its properties through a combination of exploitation, drilling, and proven engineering extraction practices, with its most significant emphasis relating to tertiary recovery operations.

Encore Merger

     On March 9, 2010, Denbury acquired Encore pursuant to an Agreement and Plan of Merger (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 $4.5 billion at that time, including the assumption of debt and the value of the noncontrolling interest in Encore Energy Partners LP (“ENP”). Under the Encore Merger Agreement, Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger. The Encore Merger was consummated on March 9, 2010, following approval by the stockholders of both Denbury and Encore, closing of a new revolving credit facility as part of the financing for the Encore Merger, and satisfaction of conditions precedent.

     The results of operations of Encore are included with those of Denbury from March 9, 2010 through June 30, 2010. Please read “Note 3. Acquisitions and Divestitures” for additional information.

Strategic Alternatives and Asset Transaction Processes for ENP

     On April 30, 2010, ENP and Denbury announced their intent to explore a broad range of strategic alternatives (“strategic process”) to enhance the value of ENP’s common units, including, but not limited to, those alternatives involving a possible merger, sale, or other transaction involving ENP, Denbury’s interest in ENP’s general partner, or all or part of the ENP common units that Denbury owns. Additionally, ENP and Denbury also announced their intent to explore a sale or other transaction involving one or more of ENP’s assets (“asset process”), initiated in light of the substantial projected capital requirements required to recognize the full potential value of certain fields owned by ENP which are possible CO₂ tertiary projects, such as the Elk Basin Field. Although either or both of these processes may result in one or more transactions involving ENP, Denbury, and/or a third party, there is no assurance that a review of strategic alternatives or consideration of an asset transaction will result in the proposal or completion of any transaction with acceptable terms.

Note 2. Basis of Presentation

Interim Financial Statements

     The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries. These financial statements and the notes thereto should be read in conjunction with Denbury’s Annual Report on Form 10-K for the year ended December 31, 2009.

     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 Denbury’s consolidated financial position as of June 30, 2010, its consolidated results of operations for the three and six months ended June 30, 2010 and 2009, and its consolidated cash flows for the six months ended June 30, 2010 and 2009.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Noncontrolling Interest

     As of June 30, 2010, Denbury owned approximately 46% of ENP’s outstanding common units. Denbury also owns 100% of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned subsidiary of Denbury, which is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with the “Consolidations” topic of the FASC, the financial position, results of operations, and cash flows of ENP are consolidated with those of Denbury from March 9, 2010 through June 30, 2010.

     As presented in the accompanying Unaudited Condensed Consolidated Balance Sheets, “Noncontrolling interest” as of June 30, 2010 of $521.2 million represents third-party ownership interests in ENP. As presented in the accompanying Unaudited Condensed Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for the three months ended June 30, 2010 of $15.0 million represents ENP’s results of operations attributable to third-party owners, and “Net income attributable to noncontrolling interest” for the six months ended June 30, 2010 of $18.3 million represents ENP’s results of operations attributable to third-party owners from March 9, 2010 through June 30, 2010.

Supplemental Cash Flow Information

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

	Six Months Ended
	June 30,
In thousands	2010			2009
Cash paid for interest, net of amounts capitalized	$	43,296		$	5,837
Interest capitalized		45,162			27,827
Cash refunds for income taxes		(1,173	)		(14,416	)
Increase (decrease) in liabilities for capital expenditures		46,170			(41,612	)
Issuance of Denbury common stock in connection with the Encore Merger		2,085,681			—

Net Income (Loss) Per Common Share

     Basic net income (loss) per common share is computed by dividing net income (loss) attributable to Denbury stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but also considers the impact of the potential dilution from stock options, unvested stock appreciation rights (“SARs”), unvested restricted stock, and unvested performance equity awards. For the three and six months ended June 30, 2010 and 2009, there were no adjustments to net income (loss) attributable to Denbury stockholders for purposes of calculating diluted net income (loss) per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands	2010		2009		2010		2009
Basic weighted average common shares		395,548		246,084		345,126		245,830
Potentially dilutive securities:
Stock options and SARs		3,980		—		3,835		—
Performance equity awards		146		—		312		—
Restricted stock		1,193		—		1,053		—
Diluted weighted average common shares		400,867		246,084		350,326		245,830

     Basic weighted average common shares excludes 3.5 million shares and 2.9 million shares at June 30, 2010 and 2009, respectively, of unvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) 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 proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. Shares of common stock issued in the Encore Merger were weighted from March 9, 2010 through June 30, 2010. The dilution impact of these shares on Denbury’s earnings per share calculations may increase in future periods depending on the market price of Denbury’s common stock during those periods.

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

	As of June 30,
In thousands	2010		2009
Stock options and SARs		4,302		11,346
Performance equity awards		—		476
Restricted stock		49		2,928
Total		4,351		14,750

CO₂Pipelines

     CO₂ pipelines are used for transportation of CO₂ to Denbury’s tertiary floods from its CO₂ source field located near Jackson, Mississippi. Denbury is continuing expansion of its CO₂ pipeline infrastructure with several pipelines currently under construction. At June 30, 2010 and December 31, 2009, Denbury had $78.7 million and $779.1 million of costs (including capitalized interest), respectively, related to pipeline construction, primarily the Green Pipeline, in progress, recorded under “CO₂ properties, equipment, and pipelines” in the accompanying Unaudited Condensed Consolidated Balance Sheets. These costs of CO₂ pipelines under construction were not being depreciated at June 30, 2010 or December 31, 2009. For financial accounting purposes, depreciation commences when the pipelines are placed into service, and each pipeline is depreciated on a straight-line basis over its estimated useful life, which ranges from 20 to 50 years. During June 2010, Denbury placed the first phase of the Green Pipeline, a 320-mile CO₂ pipeline that runs from southern Louisiana to near Houston, Texas, in service, at which time it became subject to depreciation for financial accounting purposes. This first phase runs to Denbury’s Oyster Bayou Field in Southeast Texas. Denbury filled this pipeline with CO₂ from its source at Jackson Dome during June and commenced first injection of CO₂ at the Oyster Bayou Field on June 29, 2010. The remaining $78.7 million of costs related to pipeline construction in progress at June 30, 2010 primarily consists of costs incurred for the remaining portion of the Green Pipeline to the Hastings Field. Denbury includes the net capitalized cost of pipelines which provide CO₂ to the tertiary floods that have proved tertiary reserves in the oil and natural gas full cost ceiling test.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Goodwill

     The following table summarizes the changes in Denbury’s goodwill for the period indicated:

	Six Months Ended
In thousands	June 30, 2010
Balance, beginning of period	$	169,517
Adjustment to goodwill related to the acquisition of interests in the Conroe Field (1)		318
Goodwill related to the Encore Merger (2)		1,050,337
Balance, end of period	$	1,220,172

(1)	Goodwill related to the acquisition of interests in the Conroe Field decreased due to a revision to reserve estimates, offset by closing adjustments.
(2)	See “Note 3. Acquisitions and Divestitures.”

Recently Adopted Accounting Pronouncements

     Subsequent Events.On February 24, 2010, the FASB issued guidance in the “Subsequent Events” topic of the FASC to provide updates including: (1) requiring the company to evaluate subsequent events through the date in which the financial statements are issued; (2) amending the glossary of the “Subsequent Events” topic to include the definition of “SEC filer” and exclude the definition of “Public entity”; and (3) eliminating the requirement to disclose the date through which subsequent events have been evaluated. This guidance was prospectively effective upon issuance. The adoption of this guidance did not impact Denbury’s results of operations or financial condition.

Note 3. Acquisitions and Divestitures

Merger with Encore Acquisition Company

     As previously discussed in “Note 1. Description of Business,” on March 9, 2010, the Encore Merger was consummated. The Encore Merger was financed through a combination of $1.0 billion of 8.25% Senior Subordinated Notes due 2020, which Denbury issued on February 10, 2010, a new $1.6 billion revolving credit agreement entered into on March 9, 2010, and the assumption of Encore’s remaining outstanding senior subordinated notes. Please read “Note 5. Long-Term Debt” for additional information.

     Encore shareholders received the following consideration for each share of Encore common stock they owned, depending upon the elections, if any, which they made, and the collar, proration, and allocation features of the Encore Merger Agreement so that, in the aggregate, 30% of the consideration for the outstanding shares of Encore common stock would consist of cash, and the remaining 70% of the consideration would consist of shares of Denbury common stock:

• Mixed cash/stock electing (or non-electing) Encore stockholders received $15.00 in cash and 2.4048 shares of Denbury common stock;

• All-cash electing Encore stockholders received $46.48 in cash and 0.2417 shares of Denbury common stock; and

• All-stock electing Encore stockholders (including those whose Encore restricted stock bonuses were converted into Denbury restricted stock) received 3.4354 shares of Denbury common stock.

     All Encore stock options fully vested and their intrinsic value was paid in cash. All Encore restricted stock vested and each holder had the opportunity to make the same elections as other holders of Encore common stock as described above, except for shares of Encore restricted stock granted during 2010 as a bonus pursuant to the 2009 Encore annual incentive program, which were converted into restricted shares of Denbury common stock.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     In the Encore Merger, Denbury issued approximately 135.2 million shares of its common stock and paid approximately $833.9 million in cash to Encore stockholders. The Denbury shares issued to Encore stockholders represented approximately 34% of Denbury’s common stock issued and outstanding immediately after the Encore Merger. The total fair value of the Denbury common stock issued to Encore stockholders in the Encore Merger was approximately $2.1 billion based upon Denbury’s closing price of $15.43 per share on March 9, 2010.

     The Encore Merger met the definition of a business combination under the FASC “Business Combinations” topic. As such, Denbury estimated the fair value of Encore as of the acquisition date, which is the date on which Denbury obtained control of Encore. The acquisition date for the Encore Merger was March 9, 2010. The FASC “Fair Value Measurements and Disclosures” topic defines fair value as 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 (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions should not impact the measurement of fair value unless those assumptions are consistent with market participant views.

     In applying these accounting principles, Denbury estimated the fair value of the Encore assets acquired less liabilities assumed on the acquisition date to be approximately $2.4 billion. This measurement resulted in the recognition of goodwill totaling approximately $1.1 billion. The FASC defines goodwill as an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. For this acquisition, goodwill is the excess of the consideration transferred to acquire Encore plus the fair value of the noncontrolling interest in ENP, over the acquisition date estimated fair value of the net assets acquired. Goodwill recorded in the Encore Merger primarily represents the value of the opportunity to expand Encore’s CO₂ EOR operations in the Rocky Mountain region, the experience and technical expertise of former Encore employees who have joined Denbury, and the addition of strategic areas of operations in which Denbury did not previously have a significant presence.

     The fair value of Encore was based on significant inputs not observable in the market, which FASC “Fair Value Measurements and Disclosures” topic defines as Level 3 inputs. Key assumptions include (1) NYMEX oil and natural gas futures (this input is observable), (2) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable, and possible, (3) projections of future rates of production, (4) timing and amount of future development and operating costs, (5) projected cost of CO₂ to a market participant, (6) projected recovery factors, and (7) risk-adjusted discount rates. The fair value of the oil and natural gas properties was determined using a risk-adjusted after-tax discounted cash flow analysis. Denbury applies full cost accounting rules, under which the acquisition cost of oil and natural gas properties are recognized on a cost center basis (country), of which Denbury has only one cost center (United States). All of the goodwill was assigned to this single reporting unit. None of the goodwill is deductible for income tax purposes.

Preliminary Purchase Price Allocation in Encore Merger

     Based on currently available information, the following table is a preliminary summary of the consideration issued for the Encore Merger and the fair value of the assets acquired and liabilities assumed at the acquisition date, as well as the fair value at the acquisition date of the noncontrolling interest in ENP:

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

In thousands
Consideration and noncontrolling interest:
Fair value of Denbury common stock issued (1)	$	2,085,681
Cash payment to Encore stockholders (2)		833,909
Severance payments		32,925
Consideration issued		2,952,515
Fair value of noncontrolling interest of ENP (3)		515,210
Consideration and noncontrolling interest of ENP (4)		3,467,725
Add: fair value of liabilities assumed:
Accounts payable and accrued liabilities		116,520
Oil and natural gas production payable		54,201
Current derivatives		65,954
Other current liabilities		32,986
Long-term debt		1,375,149
Asset retirement obligations, net of current portion		42,360
Long-term derivatives		35,631
Long-term deferred taxes		869,387
Other long-term liabilities		2,717
Amount attributable to liabilities assumed		2,594,905
Less: fair value of assets acquired:
Cash and cash equivalents		51,850
Accrued production receivable		124,494
Trade and other receivables		49,507
Current derivatives		29,737
Oil and natural gas properties – proved		3,340,141
Oil and natural gas properties – unevaluated		1,279,000
CO2 properties, equipment, and pipelines		7,254
Other property, plant, and equipment		11,475
Long-term derivatives		35,207
Other long-term assets		83,628
Amount attributable to assets acquired		5,012,293
Goodwill	$	1,050,337

(1)	135.2 million Denbury common shares at $15.43 per share.
(2)	Based on holders of 55.3 million Encore common shares being paid $15.00 per share plus cash payment to stock option holders of $4.5 million.
(3)	Represents fair value of the noncontrolling interest of ENP. As of March 9, 2010, there were 45.3 million ENP common units outstanding and the closing price was $21.10 per common unit. As of March 9, 2010, Encore owned approximately 46% of ENP’s outstanding common units.
(4)	The sum of the consideration issued, the noncontrolling interest of ENP, and the fair value of Encore’s long-term debt assumed totals approximately $4.8 billion, representing the aggregate purchase price.

     The above purchase price allocation for the Encore Merger is preliminary and subject to revision as Denbury finalizes the acquisition tax basis of the net assets acquired and other key assumptions utilized in the fair value models, primarily finalization of the oil and natural gas reserve analysis.

     For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, Denbury recognized $200.6 million and $260.9 million of oil, natural gas, and related product sales, respectively, related to the Encore Merger. For the three months ended June 30, 2010 and for the period from March 9, 2010 to June 30, 2010, Denbury recognized $137.8 million and $180.7 million net field operating income (oil, natural

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Notes to Unaudited Condensed Consolidated Financial Statements

gas and related product sales less lease operating expenses and production taxes and marketing expenses), respectively, related to the Encore Merger. All transaction-related costs (advisory, legal, accounting, severance, due diligence, integration, etc.) have been expensed as incurred. Denbury recognized a total of $67.8 million of transaction costs related to the Encore Merger in the six months ended June 30, 2010.

Conroe Field Acquisition

     On December 18, 2009, Denbury acquired a 91.4% interest in the Conroe Field, a significant potential tertiary flood north of Houston, Texas, for total consideration of approximately $422.9 million comprised of approximately $254.2 million in cash and 11,620,000 shares of Denbury common stock. The common stock was valued at $168.7 million based on the closing date price of Denbury’s stock on December 18, 2009 of $14.52 per share. The effective date of purchase was December 1, 2009. The cash amount paid at closing was $268.5 million, which includes $15.6 million for amounts in escrow accounts reserved for plugging and abandonment and other adjustments. Denbury recorded approximately $31.0 million of goodwill related to the acquisition of interests in the Conroe Field.

     Denbury shares issued in a private placement in conjunction with the purchase of interests in the Conroe Field were subsequently registered for resale with the SEC on February 2, 2010, as required under a registration rights agreement. The registration rights agreement provides that the registration statement for the shares remain effective for approximately one year.

Hastings Field Acquisition

     During November 2006, Denbury entered into an agreement with a subsidiary of Venoco, Inc. (“Venoco”), which gave Denbury an option to purchase Venoco’s interests in the Hastings Field, a strategically significant potential tertiary flood candidate located near Houston, Texas. Denbury exercised the purchase option prior to September 2008, and closed the acquisition during February 2009. As consideration for the option agreement, during 2006 through 2008, Denbury made cash payments totaling $50 million, which it recorded as a deposit. The remaining purchase price of approximately $196 million was paid in cash, and was determined as of January 1, 2009 (the effective date) with closing on February 2, 2009. The final closing adjustments were completed during the three months ended September 30, 2009. The final closing price, adjusted for interim net cash flows between the effective date and closing date of the acquisition (including minor purchase price adjustments), totaled approximately $246.8 million. Denbury recorded approximately $138.8 million of goodwill related to the acquisition of interests in the Hastings Field.

Barnett Shale Dispositions

     In May 2009, Denbury entered into an agreement to sell 60% of its Barnett Shale natural gas assets to Talon Oil and Gas LLC (“Talon”), a privately held company, for $270 million (before closing adjustments). Denbury closed approximately three-quarters of the sale in June 2009 and closed the remainder of the sale in July 2009. Net proceeds were approximately $259.8 million (after closing adjustments, and net of $8.1 million for natural gas swaps transferred in the sale). The effective date under the agreement was June 1, 2009. Denbury did not record a gain or loss on the sale in accordance with the full cost method of accounting.

     In December 2009, Denbury closed the sale of the remaining 40% of its Barnett Shale natural gas assets to Talon for $210 million (before closing adjustments). Net proceeds were approximately $209.9 million (after closing adjustments). The effective date under the agreement was December 1, 2009. Denbury did not record a gain or loss on the sale in accordance with the full cost method of accounting. Further, the sale was structured as a deferred like-kind exchange in conjunction with Denbury’s acquisition of interests in the Conroe Field in order to defer most of the tax impacts of the sale.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Sale of Interests in Genesis Energy, L.P. (“Genesis”)

     In February 2010, Denbury sold its interest in Genesis Energy, LLC, the general partner of Genesis, for net proceeds of approximately $84 million, after giving effect to the change of control provision of the incentive compensation agreement with Genesis’ management, which was triggered and under which Denbury paid a total of $14.9 million comprised of deferred compensation of $1.9 million and change of control redemption of $13.0 million. In February 2010, Denbury recognized general and administrative expense of $1.1 million associated with the $14.9 million payment. The remainder of the payment had been previously accrued in Denbury’s financial statements as of December 31, 2009. In March 2010, Denbury sold all of its Genesis common units in a secondary public offering for net proceeds of approximately $79 million. As a result, Denbury no longer holds any interest in Genesis. Denbury recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.

Sale of Southern Properties

     On May 14, 2010, Denbury sold certain oil and natural gas properties and related assets acquired in the Encore Merger, primarily located in the Permian Basin in West Texas and southeastern New Mexico; the Mid-continent area, which includes the Anadarko Basin in Oklahoma, Texas, and Kansas; and the East Texas Basin (the “Southern Assets”) to Quantum Resources Management, LLC for consideration of $883.9 million after closing adjustments and including a prior $45 million deposit. The effective date of the sale was May 1, 2010. Denbury did not record a gain or loss on the sale in accordance with the full cost method of accounting. The properties acquired in the Encore Merger in the southern part of the United States which were not sold include the Haynesville Shale, Paradox Basin, Cleveland Sand Play, and Tuscaloosa Marine Shale properties. Although the sale of the Southern Assets triggered an impairment test of goodwill, no impairment charges were made or required during the second quarter of 2010.

Pro Forma Information

     The following unaudited pro forma condensed financial data for the three and six months ended June 30, 2010 gives effect to the Encore Merger as if it had occurred on January 1, 2010. The following unaudited pro forma condensed financial data for the three and six months ended June 30, 2009 gives effect to the Encore Merger, the acquisition of interests in the Conroe Field in December 2009 and the acquisition of interests in the Hastings Field in February 2009 as if each had occurred on January 1, 2009. The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
In thousands, except per share amounts	2010		2009			2010		2009
Pro forma total revenues	$	497,210	$	388,865		$	1,112,481	$	688,856
Pro forma net income (loss) attributable to Denbury stockholders	$	135,494	$	(134,037	)	$	247,423	$	(168,566	)
Pro forma net income (loss) per common share:
Basic	$	0.34	$	(0.34	)	$	0.63	$	(0.43	)
Diluted	$	0.34	$	(0.34	)	$	0.62	$	(0.43	)

Note 4. Asset Retirement Obligations

     In general, Denbury’s future asset retirement obligations relate to future costs associated with plugging and abandonment of its oil, natural gas, and CO₂ wells, removal of equipment and facilities from leased acreage, and land restoration. The fair value of a liability for an asset retirement is recorded in the period in which it is incurred, discounted to its present value using Denbury’s credit-adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     The following table summarizes the changes in Denbury’s asset retirement obligations for the period indicated:

	Six Months Ended
In thousands	June 30, 2010
Balance, beginning of period	$	54,338
Liabilities incurred and assumed during period		2,222
Liabilities assumed in the Encore Merger		43,783
Revisions in estimated retirement obligations		1,702
Liabilities settled during period		(3,216	)
Accretion expense		2,799
Sales of properties		(7,520	)
Balance, end of period	$	94,108

     At June 30, 2010 and December 31, 2009, approximately $2.4 million and $1.1 million, respectively, of Denbury’s asset retirement obligations were classified in “Accounts payable and accrued liabilities” under current liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets. Denbury has escrow accounts that are legally restricted for certain of its asset retirement obligations. The balances of these escrow accounts were approximately $32.8 million and $22.8 million at June 30, 2010 and December 31, 2009, respectively, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.

Note 5. Long-Term Debt

     The following table shows the components of Denbury’s long-term debt as of the periods indicated:

	June 30,		December 31,
In thousands, except percentages	2010		2009
Denbury Credit Agreement	$	40,000	$	—
ENP Credit Agreement		245,000		—
Senior bank loan (replaced with Denbury Credit Agreement)		—		125,000
7.5% Senior Subordinated Notes due 2013, net of discount of $534 and $631, respectively		224,466		224,369
6.25% Senior Subordinated Notes due 2014, including premium of $12		1,084		—
7.5% Senior Subordinated Notes due 2015, including premium of $470 and $513, respectively		300,470		300,513
6.0% Senior Subordinated Notes due 2015, including premium of $6		490		—
9.5% Senior Subordinated Notes due 2016, including premium of $15,957		240,877		—
9.75% Senior Subordinated Notes due 2016, net of discount of $24,281 and $26,424, respectively		402,069		399,926
7.25% Senior Subordinated Notes due 2017, including premium of $27		2,277		—
8.25% Senior Subordinated Notes due 2020		996,273		—
Northeast Jackson Dome pipeline financing		169,024		170,633
Free State pipeline financing		81,822		79,987
Capital lease obligations		8,017		5,948
Total		2,711,869		1,306,376
Less current portion		7,464		5,308
Long-term debt and capital lease obligations	$	2,704,405	$	1,301,068

New $1.6 Billion Revolving Credit Agreement

     On March 9, 2010, Denbury entered into a new $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. (“JPMorgan”), as administrative agent, and 23 other lenders as party thereto (the “Denbury Credit Agreement”). Borrowings under the Denbury Credit Agreement, coupled with the funds from Denbury’s issuance of $1.0 billion of 8.25% Senior Subordinated Notes due 2020, were used to:

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

• fund the cash portion of the consideration issued in the Encore Merger (inclusive of payments made to stock option holders);

• repay amounts outstanding under Denbury’s then existing $750 million revolving credit agreement, which had $125 million outstanding as of March 9, 2010;

• repay amounts outstanding under Encore’s then existing revolving credit agreement, which had $265 million outstanding as of March 9, 2010;

• pay Encore’s severance costs;

• pay transaction fees and expenses; and

• provide additional liquidity.

     Availability under the Denbury Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1, beginning in November 2010, and upon requested special redeterminations. The Denbury Credit Agreement provides for a borrowing base of $1.6 billion. The borrowing base represents the amount that can be borrowed based on the reserves and certain other oil and natural gas assets of Denbury and its restricted subsidiaries, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the Denbury Credit Agreement. The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which Denbury has no control. If the borrowing base were to be less than outstanding borrowings under the Denbury Credit Agreement, Denbury would be required to repay the deficit over a period of four months. In conjunction with the sale of the Southern Assets, lending banks performed a redetermination of the borrowing base under the Denbury Credit Agreement and left the borrowing base unchanged. Denbury incurs a commitment fee of 0.5% on the unused portion of the credit facility or if less, the borrowing base. Loans under the Denbury Credit Agreement mature in March 2014.

     The Denbury Credit Agreement is secured by substantially all of the proved oil and natural gas properties of Denbury’s restricted subsidiaries and by the equity interests of Denbury’s restricted subsidiaries. In addition, Denbury’s obligations under the Denbury Credit Agreement are guaranteed by its restricted subsidiaries. The restricted subsidiaries include most of the subsidiaries of the combined company after the Encore Merger, excluding Denbury’s non-guarantor subsidiaries.

     The Denbury Credit Agreement contains several restrictive covenants including, among others:

• a prohibition on the payment of dividends to parties other than Denbury and its restricted subsidiaries;

• a requirement to maintain a current ratio, as determined under the Denbury Credit Agreement, of not less than 1.0 to 1.0;

• a maximum permitted ratio of debt to adjusted EBITDA (as defined in the Denbury Credit Agreement) of Denbury and its restricted subsidiaries of not more than 4.5 to 1.0 in 2010 and 4.0 to 1.0 in 2011 and thereafter; and

• a prohibition against incurring debt, subject to permitted exceptions.

     Additionally, there is a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts.

     Loans under the Denbury Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin of 2.0% to 3.0% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the base rate plus the applicable margin of 1.0% to 2.0% based on the ratio of outstanding borrowings to the borrowing base. The “Eurodollar rate” for any interest period (either one, two, three, six, nine, or twelve months, as selected by Denbury) is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (1) the annual rate of interest announced by and JPMorgan as its “prime rate,” (2) the federal funds effective rate plus 0.5%, and (3) the Adjusted Eurodollar Rate (as defined in the Denbury Credit Agreement) for a one-month interest period plus 1.0%.

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DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Encore Energy Partners Operating LLC Credit Agreement

     Encore Energy Partners Operating LLC (“OLLC”), a wholly-owned subsidiary of ENP, is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “ENP Credit Agreement”). The ENP Credit Agreement matures on March 7, 2012. In November 2009, OLLC amended the ENP Credit Agreement, effective upon the closing of the Encore Merger, to, among other things, permit the consummation of the Encore Merger despite its being a “Change of Control” under the ENP Credit Agreement.

     The ENP Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the ENP Credit Agreement is $475 million. Availability under the ENP Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. On June 14, 2010, the borrowing base under the ENP Credit Agreement was reaffirmed at $375 million. As of June 30, 2010, the borrowing base was $375 million and there were $245 million of outstanding borrowings and $130 million of borrowing capacity under the ENP Credit Agreement.

     Obligations under the ENP Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the ENP Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Denbury consolidates the debt of ENP with that of its own; however, obligations under the ENP Credit Agreement are non-recourse to Denbury and its restricted subsidiaries.

Issuance of 8.25% Senior Subordinated Notes due 2020

     On February 10, 2010, Denbury issued $1.0 billion of 8.25% Senior Subordinated Notes due 2020 (the “2020 Notes”), for net proceeds after underwriting discounts and commissions of $980 million. The 2020 Notes were sold at par. Upon the closing of the Encore Merger, $400 million of the net proceeds were used to finance a portion of the Encore Merger consideration. Under the indenture governing the 2020 Notes, to the extent that fewer than $600 million principal amount of Encore’s outstanding senior subordinated notes were repurchased in tender offers or change of control repurchases under the Encore indentures, Denbury was required to redeem an equal amount of the 2020 Notes, plus accrued and unpaid interest. Denbury redeemed $500.5 million principal amount of Encore’s outstanding senior subordinated notes in a tender offer, repurchased an additional $95.7 million principal amount of Encore’s outstanding senior subordinated notes under change of control provisions, and redeemed $3.7 million principal amount of the 2020 Notes. Please read “Tender Offers and Consent Solicitations for Encore’s Senior Subordinated Notes; Supplements to Indentures Governing Encore’s Senior Subordinated Notes” below.

     The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August 15 of each year, beginning August 15, 2010. Denbury may redeem the 2020 Notes in whole or in part at its option beginning February 15, 2015, at the following redemption prices:

• 104.125% after February 15, 2015;

• 102.75% after February 15, 2016;

• 101.375% after February 15, 2017; and

• 100% after February 15, 2018.

     Prior to February 15, 2013, Denbury may at its option redeem up to an aggregate of 35% of the principal amount of the 2020 Notes at a price of 108.25% with the proceeds of certain equity offerings. In addition, at any time prior to February 15, 2015, Denbury may redeem 100% of the principal amount of the 2020 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 Denbury’s ability to incur additional debt, pay dividends on its common stock, make investments, create liens on its assets, engage in transactions with its affiliates, transfer or sell assets,

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Notes to Unaudited Condensed Consolidated Financial Statements

consolidate or merge, or sell substantially all of its assets. The 2020 Notes are not subject to any sinking fund requirements. Certain of Denbury’s subsidiaries fully and unconditionally guarantee this debt.

Supplements to Indentures Governing Denbury’s Senior Subordinated Notes

     On March 9, 2010, upon closing of the Encore Merger, Denbury became an obligor, as successor in interest to Encore, with respect to Encore senior subordinated notes, which are governed by four indentures covering an aggregate original principal amount of $825 million. In conjunction with the closing of the Encore Merger, Denbury and its subsidiaries entered into supplemental indentures to add subsidiary guarantors, as required under the Encore indentures as well as the indentures governing Denbury’s senior subordinated notes. The Encore legacy subsidiaries, with permitted exceptions, became guarantors under the Denbury indentures that were in effect prior to the Encore Merger and the Denbury legacy subsidiaries, with permitted exceptions, became guarantors under the Encore indentures with respect to which Denbury succeeded Encore.

Tender Offers and Consent Solicitations for Encore’s Senior Subordinated Notes; Supplements to Indentures Governing Encore’s Senior Subordinated Notes

     On February 8, 2010, Denbury commenced a cash tender offer to repurchase $600 million principal amount of Encore’s $825 million senior subordinated notes which were governed by three of Encore’s four indentures and solicited consents to amend each of those three indentures to eliminate most of the indenture covenants. Those indentures are the indentures to which Encore was a party prior to the Encore Merger governing their 6.25% Senior Subordinated Notes due 2014 (the “6.25% Notes”), their 6.0% Senior Subordinated Notes due 2015 (the “6.0% Notes”), and their 7.25% Senior Subordinated Notes due 2017 (the “7.25% Notes”).

     On March 10, 2010, upon expiration of the tender offers and consent solicitations, Denbury accepted for purchase all notes tendered in the tender offer. The total amount of notes that Denbury purchased was approximately $500.5 million in principal amount of the $600 million in original principal amount for which tenders were made, leaving outstanding approximately $99.5 million of the $600 million of notes for which Denbury made tender offers.

     The tender of the notes also constituted the delivery of consents of holders of the notes to eliminate or modify certain provisions contained in each of the three indentures governing the Encore senior subordinated notes for which tender offers were made. Denbury received sufficient consents in the solicitations to amend these three Encore indentures effective upon the Encore Merger. The amendments of the three indentures governing the $600 million of notes subject to the tender offers eliminated most of the restrictive covenants, including covenants requiring the filing of SEC reports; restricting certain payments; limiting indebtedness; restricting distributions from certain restricted subsidiaries, affiliate transactions, and liens; requiring future subsidiaries to guarantee the applicable notes; requiring the delivery of certificates concerning compliance with the applicable indenture; certain provisions of covenants relating to mergers and consolidations; and certain events of default in the indentures. The amendments do not apply to the 9.50% Senior Subordinated Notes due 2016 (the “9.5% Notes”).

     On March 12, 2010, Denbury announced cash change of control offers to purchase, for 101% of the face amount, the remaining $324.5 million of senior subordinated notes outstanding under the four Encore indentures, as required by each of the Encore indentures. In April 2010, Denbury purchased approximately $95.7 million of these senior subordinated notes, leaving approximately $228.7 million of former Encore notes outstanding.

Encore Indentures

     In addition to the three indentures that govern the Encore senior subordinated notes for which Denbury made tender offers, as a result of the Encore Merger, Denbury also became successor in interest to Encore under the Encore indenture with respect to the 9.5% Notes in the original principal amount of $225 million (the “9.5% Indenture”). Interest on the 9.5% Notes is due semi-annually on May 1 and November 1. The 9.5% Notes mature on May 1, 2016. The material terms of the 9.5% Indenture include covenants requiring the filing of SEC reports; restricting certain payments; limiting indebtedness; restricting distributions from certain restricted subsidiaries,

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Notes to Unaudited Condensed Consolidated Financial Statements

affiliate transactions, and liens; requiring certain subsidiaries to deliver guarantees of the notes; requiring the delivery of certificates concerning compliance with the indenture; and covenants relating to mergers and consolidations.

     All of the Encore indentures, including the 9.5% Indenture, also have covenants limiting the sale of assets and providing a put right by holders upon change of control. The Encore indentures also contain certain affirmative, negative, and financial covenants, which include a requirement that Denbury maintain a current ratio (as defined in the Encore indentures) of not less than 1.0 to 1.0 and a requirement that Denbury maintain a ratio of consolidated EBITDA (as defined in the Encore indentures) to consolidated interest expense of not less than 2.5 to 1.0.

Note 6. Derivative Instruments and Hedging Activities

Derivative Policy

     Denbury applies the provisions of the “Derivatives” topic of the FASC, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss within equity until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

     Denbury has elected to designate ENP’s outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Unaudited Condensed Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings and included in “Derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

     Denbury does not apply hedge accounting treatment to its 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 included in “Derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

Oil and Natural Gas Derivative Contracts

     From time to time, Denbury enters into various oil and natural gas derivative contracts to provide an economic hedge of its exposure to commodity price risk associated with anticipated future oil and natural gas production. Denbury does not hold or issue derivative financial instruments for trading purposes. These contracts consist of price floors, collars, and fixed price swaps. Historically, Denbury has hedged up to 80% of its anticipated production for the following year to provide it with a reasonably certain amount of cash flow to cover most of its budgeted exploration and development expenditures without incurring significant debt. Also, in light of the Encore Merger, and Denbury’s desire to protect its cash flows given the increased debt levels, in March 2010, Denbury entered into costless collar crude oil contracts covering 17,000 Bbls/d during the first half of 2011 and in June 2010, it entered into costless collar crude oil contracts covering an additional 8,000 Bbls/d during the third quarter of 2011.

     Denbury manages and controls market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. Denbury attempts to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures, and diversification. All of Denbury’s and ENP’s commodity derivative contracts are with parties that are lenders under their respective credit agreements. Denbury has included an estimate of nonperformance risk in the fair value measurement of its commodity derivative contracts as required by FASC guidance on fair value. At June 30, 2010 and December 31, 2009, the net asset (liability) of Denbury’s open commodity derivative contracts of $109.7 million and ($128.7) million, respectively, included a reduction of $1.1 million and $0.8 million, respectively, for estimated nonperformance risk.

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Notes to Unaudited Condensed Consolidated Financial Statements

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands	2010			2009			2010			2009
Receipts (payments) on settlement of oil derivative contracts	$	(13,829	)	$	42,002		$	(77,379	)	$	127,838
Receipts on settlement of natural gas derivative contracts		16,630			—			20,379			—
Fair value adjustments to derivative contracts income (expense)		125,190			(194,791	)		226,029			(301,142	)
Ineffectiveness on interest rate swaps		683			—			870			—
Derivatives income (expense)	$	128,674		$	(152,789	)	$	169,899		$	(173,304	)

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Notes to Unaudited Condensed Consolidated Financial Statements

Fair Value of Commodity Derivative Contracts Not Classified as Hedging Instruments

												Estimated Fair Value
						NYMEX Contract Prices Per Bbl						Asset (Liability)
			Type of			Weighted Average Price						June 30,			December 31,
Year		Months	Contract	Bbls/d		Swap		Floor		Ceiling		2010			2009
												In thousands
Oil Contracts:
2010		Jan – Mar	Swap		31,635	$	55.96	$	—	$	—	$	—		$	(63,525	)
			Collar		11,440		—		67.72		85.86		—			95
			Put		9,325		—		67.84		—		—			—
		Total Jan – Mar 2010			52,400							$	—		$	(63,430	)
		Apr – June	Swap		6,635	$	71.45	$	—	$	—	$	—		$	—
			Collar		36,440		—		55.56		78.56		—			(24,741	)
			Put		9,325		—		67.84		—		—			—
		Total Apr – June 2010			52,400							$	—		$	(24,741	)
		July – Sept	Swap		6,635	$	71.45	$	—	$	—	$	(2,916	)	$	—
	��		Collar		36,440		—		60.71		82.67		(4,351	)		(20,761	)
			Put		9,325		—		67.84		—		1,502			—
		Total July – Sept 2010			52,400							$	(5,765	)	$	(20,761	)
		Oct – Dec	Swap		6,635	$	71.45	$	—	$	—	$	(3,690	)	$	—
			Collar		36,440		—		62.42		88.81		(2,653	)		(13,320	)
			Put		9,325		—		67.84		—		3,025			—
		Total Oct – Dec 2010			52,400							$	(3,318	)	$	(13,320	)
2011		Jan – Mar	Swap		1,635	$	77.39	$	—	$	—	$	(167	)	$	—
			Collar		44,940		—		70.43		100.05		12,725			177
			Put		8,825		—		70.85		—		4,505			—
		Total Jan – Mar 2011			55,400							$	17,063		$	177
		Apr – June	Swap		1,635	$	77.39	$	—	$	—	$	(297	)	$	—
			Collar		44,940		—		70.43		100.05		12,537			(318	)
			Put		8,825		—		70.85		—		5,296			—
		Total Apr – June 2011			55,400							$	17,536		$	(318	)
		July – Sept	Swap		1,635	$	77.39	$	—	$	—	$	(380	)	$	—
			Collar		35,940		—		70.54		99.79		8,897			(1,078	)
			Put		8,825		—		70.85		—		6,008			—
		Total July – Sept 2011			46,400							$	14,525		$	(1,078	)
		Oct – Dec	Swap		1,635	$	77.39	$	—	$	—	$	(440	)	$	—
			Collar		27,940		—		70.69		101.72		7,119			(2,533	)
			Put		8,825		—		70.85		—		6,408			—
		Total Oct – Dec 2011			38,400							$	13,087		$	(2,533	)
2012		Jan – Dec	Swap		2,135	$	78.36	$	—	$	—	$	(2,120	)	$	—
			Collar		750		—		68.33		81.12		(1,581	)		—
			Put		2,135		—		65.59		—		5,335			—
		Total Jan – Dec 2012			5,020							$	1,634		$	—
								Total Oil Contracts				$	54,762		$	(126,004	)

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Notes to Unaudited Condensed Consolidated Financial Statements

											Estimated Fair Value
					Contract Prices Per Mcf						Asset (Liability)
		Type of			Weighted Average Price						June 30,		December 31,
Year	Months	Contract	Mcf/d		Swap		Floor		Ceiling		2010		2009
											In thousands
Natural Gas Contracts:
2010	Jan – Mar	Swap		85,002	$	5.80	$	—	$	—	$	—	$	92
		Collar		3,800		—		7.20		9.58		—		—
		Put		4,698		—		8.07		—		—		—
	Total Jan – Mar 2010			93,500							$	—	$	92
	Apr – June	Swap		85,002	$	5.80	$	—	$	—	$	—	$	397
		Collar		3,800		—		7.20		9.58		—		—
		Put		4,698		—		8.07		—		—		—
	Total Apr – June 2010			93,500							$	—	$	397
	July – Sept	Swap		65,002	$	5.98	$	—	$	—	$	8,338	$	(294	)
		Collar		13,800		—		5.70		7.17		1,573		—
		Put		4,698		—		8.07		—		1,514		—
	Total July – Sept 2010			83,500							$	11,425	$	(294	)
	Oct – Dec	Swap		65,002	$	5.98	$	—	$	—	$	6,577	$	(1,954	)
		Collar		13,800		—		5.70		7.17		1,426		—
		Put		4,698		—		8.07		—		1,427		—
	Total Oct – Dec 2010			83,500							$	9,430	$	(1,954	)
2011	Jan – Dec	Swap		55,502	$	6.35	$	—	$	—	$	22,354	$	(981	)
		Put		3,398		—		6.31		—		1,860		—
	Total Jan – Dec 2011			58,900							$	24,214	$	(981	)
2012	Jan – Dec	Swap		26,002	$	6.46	$	—	$	—	$	9,266	$	—
		Put		898		—		6.76		—		575		—
	Total Jan – Dec 2012			26,900							$	9,841	$	—
					Total Natural Gas Contracts						$	54,910	$	(2,740	)
					Total Commodity Derivative Contracts						$	109,672	$	(128,744	)

     The table above includes ENP commodity derivative contracts. As of June 30, 2010, ENP’s oil derivative contracts cover 4,650 Bbls/d, 4,650 Bbls/d, and 3,770 Bbls/d during 2010, 2011 and 2012, respectively. As of June 30, 2010, ENP’s natural gas derivative contracts cover 14,500 Mcf/d, 11,900 Mcf/d and 6,900 Mcf/d during 2010, 2011 and 2012, respectively. ENP’s commodity derivative contracts include swaps, collars and puts. The fair values of ENP’s oil and natural gas derivative contracts were $8.5 million and $14.8 million, respectively, at June 30, 2010.

     As of June 30, 2010, Denbury had $38.1 million of deferred premiums payable, which relate to various oil and natural gas floor contracts and are payable on a monthly basis from July 2010 to January 2013. These premiums are excluded from the above tables.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit agreement to a weighted average fixed rate. The following table

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Notes to Unaudited Condensed Consolidated Financial Statements

summarizes ENP’s open interest rate swaps as of June 30, 2010, all of which were entered into with Bank of America, N.A.:

Term	Notional Amount		Fixed Rate			Floating Rate
	(In thousands)
July 2010 – Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
July 2010 – Jan. 2011		25,000		2.9650	%	1-month LIBOR
July 2010 – Jan. 2011		25,000		2.9613	%	1-month LIBOR
July 2010 – Mar. 2012		50,000		2.4200	%	1-month LIBOR

Additional Disclosures about Derivative Instruments

     At June 30, 2010 and December 31, 2009, Denbury had derivative financial instruments recorded in the accompanying Unaudited Condensed Consolidated Balance Sheets as follows:

		Estimated Fair Value
		Asset (Liability)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2010			2009
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative asset:
Oil contracts	Derivative assets – current	$	43,375		$	309
Natural gas contracts	Derivative assets – current		33,919			—
Oil contracts	Derivative assets – long-term		33,864			506
Natural gas contracts	Derivative assets – long-term		20,991			—
Derivative liability:
Oil contracts	Derivative liabilities – current		(17,858	)		(122,561	)
Natural gas contracts	Derivative liabilities – current		—			(1,759	)
Deferred premiums	Derivative liabilities – current		(23,667	)		—
Oil contracts	Derivative liabilities – long-term		(4,619	)		(4,258	)
Natural gas contracts	Derivative liabilities – long-term		—			(981	)
Deferred premiums	Derivative liabilities – long-term		(14,429	)		—
Total derivatives not designated as hedging instruments			71,576			(128,744	)
Derivatives designated as hedging instruments:
Derivative liability:
Interest rate swaps	Derivative liabilities – current		(2,418	)		—
Interest rate swaps	Derivative liabilities – long-term		(534	)		—
Total derivatives designated as hedging instruments			(2,952	)		—
Total derivatives		$	68,624		$	(128,744	)

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Notes to Unaudited Condensed Consolidated Financial Statements

     For the three and six months ended June 30, 2010 and 2009, the net effect on income of derivative instruments not designated as hedges was as follows:

		Amount of Gain/(Loss)						Amount of Gain/(Loss)
		Recognized in Income						Recognized in Income
		Three Months Ended						Six Months Ended
	Location of Gain/(Loss)	June 30,						June 30,
Type of Contract	Recognized in Income	2010			2009			2010		2009
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity contracts:
Oil contracts	Derivatives income (expense)	$	131,270		$	(147,316	)	$	129,541	$	(157,341	)
Natural gas contracts	Derivatives income (expense)		(3,279	)		(5,473	)		39,488		(15,963	)
Total derivatives not designated as hedging instruments		$	127,991		$	(152,789	)	$	169,029	$	(173,304	)

     Please read “Note 7. Fair Value Measurements” for additional information regarding Denbury’s derivative instruments.

Note 7. Fair Value Measurements

Fair Value Hierarchy

     Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Denbury utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Denbury primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, Denbury utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Denbury is 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. During 2009 and the first six months of 2010, Denbury had no Level 1 recurring measurements.

• Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

• 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. Denbury’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange—traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. Denbury uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are

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Notes to Unaudited Condensed Consolidated Financial Statements

classified within the Level 3 valuation hierarchy. The observable inputs of Denbury’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable inputs of Denbury’s valuation model include volatility. The implied volatilities for Denbury’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

     Denbury adjusts the valuations from the valuation model for nonperformance risk, using management’s 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 Denbury’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated:

	Fair Value Measurements Using:
			Significant
	Quoted Prices		Other			Significant
	in Active		Observable			Unobservable
	Markets		Inputs			Inputs
In thousands	(Level 1)		(Level 2)			(Level 3)			Total
June 30, 2010
Assets:
Oil and natural gas derivative contracts	$	—	$	86,068		$	46,081		$	132,149
Liabilities:
Oil and natural gas derivative contracts		—		(16,679	)		(5,798	)		(22,477	)
Interest rate swaps		—		(2,952	)		—			(2,952	)
Total	$	—	$	66,437		$	40,283		$	106,720
December 31, 2009
Assets:
Oil derivative contracts	$	—	$	815		$	—		$	815
Liabilities:
Oil and natural gas derivative contracts		—		(129,559	)		—			(129,559	)
Total	$	—	$	(128,744	)	$	—		$	(128,744	)

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Notes to Unaudited Condensed Consolidated Financial Statements

     The following table summarizes the changes in the fair value of Denbury’s Level 3 assets and liabilities for the six months ended June 30, 2010:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil		Natural Gas
	Derivative		Derivative
	Contracts		Contracts
In thousands	Floors and Caps		Floors and Caps			Total
Balance at December 31, 2009	$	—	$	—		$	—
Included in earnings		20,804		2,329			23,133
Commodity derivative contracts acquired in Encore Merger		8,942		9,645			18,587
Receipts (payments) on settlement of commodity derivative contracts		2,163		(3,600	)		(1,437	)
Balance at June 30, 2010	$	31,909	$	8,374		$	40,283
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	20,804	$	2,329		$	23,133

     Since Denbury does not use hedge accounting for its commodity derivative contracts, all gains and losses on its assets and liabilities are included in “Derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

     All fair values have been adjusted for nonperformance risk resulting in a decrease of the net commodity derivative liability of approximately $1.1 million as of June 30, 2010. For commodity derivative contracts which are in an asset position, Denbury uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, Denbury uses the average credit default swap rating of its peer companies as Denbury does not have its own credit default swap rating.

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Notes to Unaudited Condensed Consolidated Financial Statements

     The following table sets forth the carrying amount and estimated fair value of financial instruments as of the dates indicated:

	June 30, 2010				December 31, 2009
	Carrying		Estimated		Carrying		Estimated
In thousands, except percentages	Amount		Fair Value		Amount		Fair Value
Assets:
Commodity derivative contracts	$	132,149	$	132,149	$	815	$	815
Liabilities:
Denbury Credit Agreement		40,000		38,284		—		—
ENP Credit Agreement		245,000		240,485		—		—
Senior bank loan (replaced with Denbury Credit Agreement)		—		—		125,000		122,500
7.5% Senior Subordinated Notes due 2013		224,466		228,094		224,369		226,125
6.25% Senior Subordinated Notes due 2014		1,084		1,072		—		—
7.5% Senior Subordinated Notes due 2015		300,470		303,000		300,513		299,250
6.0% Senior Subordinated Notes due 2015		490		484		—		—
9.5% Senior Subordinated Notes due 2016		240,877		238,415		—		—
9.75% Senior Subordinated Notes due 2016		402,069		460,458		399,926		455,129
7.25% Senior Subordinated Notes due 2017		2,277		2,250		—		—
8.25% Senior Subordinated Notes due 2020		996,273		1,041,105		—		—
Commodity derivative contracts		22,477		22,477		129,559		129,559
Deferred premiums on commodity derivative contracts		38,096		38,096		—		—
Interest rate swaps		2,952		2,952		—		—

     The book values of cash and cash equivalents, accrued production receivable, trade and other receivables, net, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The fair values of the senior subordinated notes were determined using open market quotes. The difference between book value and fair value of the senior subordinated notes represents the premium or discount on that date. The carrying values of Denbury’s revolving credit agreements approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to Denbury for those periods; however, the estimated fair value has been adjusted for estimated nonperformance risk of approximately $6.2 million and $2.5 million at June 30, 2010 and December 31, 2009, respectively. The nonperformance risk was determined utilizing industry credit default swaps. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Unaudited Condensed Consolidated Balance Sheets. Deferred premiums on commodity derivative contracts were recorded at their fair value at the time they were acquired from Encore and Denbury accretes that value to the eventual settlement price by recording interest expense each period.

     Please read “Note 6. Derivative Instruments and Hedging Activities” for additional information regarding Denbury’s derivative instruments.

Note 8. Income Taxes

     Denbury’s effective tax rate has historically been slightly lower than its estimated statutory rate due to the impact of certain items such as the domestic production activities deduction, offset in part by certain non-cash stock-based compensation that cannot be deducted for tax purposes in the same manner as book expense. As a result of the Encore Merger, Denbury’s statutory rate increased, which required Denbury to remeasure its deferred tax liabilities resulting in an additional income tax provision of approximately $10 million. As a result of the sale of the Southern Assets, Denbury’s statutory rate decreased, which required Denbury to remeasure its deferred tax liabilities resulting in an income tax benefit of approximately $3 million. The combination of these items increased Denbury’s effective tax rate to 38.7% during the six months ended June 30, 2010.

29

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     In the second 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 which led us to apply for refunds of certain amounts related thereto on our 2004 and 2006 federal income tax returns. In the course of an IRS audit of those refund claims, the IRS examination team has questioned the change in accounting method and the ruling received from the National Office of the IRS in 2008. Together with the IRS examination team, we have submitted a request to the National Office of the IRS for a Technical Advice Memorandum (TAM) regarding these issues, which is under consideration by the National Office. Although we have not recorded an uncertain tax position related to these deductions as we expect to receive those tax refunds, given the existence of the TAM process related to those refunds, the payment of those tax refunds of approximately $10.6 million for tax years through 2006 is not free from doubt.

Note 9. Accounts Payable and Accrued Liabilities

     The following table summarizes Denbury’s accounts payable and accrued liabilities as of the periods indicated:

	June 30,		December 31,
In thousands	2010		2009
Accounts payable	$	52,411	$	40,140
Accrued commodity derivative contract settlements		1,984		—
Accrued exploration and development costs		140,919		40,375
Accrued compensation		22,809		35,292
Accrued lease operating expense		28,241		14,512
Accrued interest		57,928		24,214
Taxes payable		15,944		5,358
Asset retirement obligations		2,366		1,087
Other		37,456		8,896
Total	$	360,058	$	169,874

Note 10. Commitments and Contingencies

     In conjunction with the Encore Merger, Denbury acquired certain commitments, including: remaining outstanding principal and interest on the 6.5% Notes, the 6.0% Notes, the 9.5% Notes, and the 7.25% Notes previously issued by Encore, derivative contracts, operating leases, and asset retirement obligations. The Encore Merger is discussed in Note 3, asset retirement obligations are discussed in Note 4, long-term debt is discussed in Note 5, and derivative contracts are discussed in Notes 6 and 7. Operating leases assumed from Encore require payments of approximately $2.0 million in the remainder of 2010, $7.0 million in 2011 through 2012, and $2.6 million in 2013. In addition, Denbury entered into a new lease for its corporate headquarters with a 12-year term that has total minimum monthly payments which aggregate approximately $55.6 million.

     We are involved in various lawsuits, claims and 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 or overall trends in 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 11. Condensed Consolidating Financial Information

     Denbury’s subordinated debt is fully and unconditionally guaranteed jointly and severally by certain of its subsidiaries, except that with respect to Denbury’s $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. In the case of the 6.25% Notes, the 6% Notes, the 7.25% Notes and the 9.5% Notes previously issued by Encore, Denbury is the sole

30

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

issuer by virtue of the fact that it is the successor in interest to Encore with respect to all such notes. Each subsidiary guarantor and the subsidiary co-obligor are wholly-owned, directly or indirectly, by Denbury Resources Inc.

     All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between Denbury Resources Inc., Denbury Onshore, LLC, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with Denbury Resources Inc. and then eliminated to arrive at consolidated totals per the accompanying Unaudited Condensed Consolidated Financial Statements.

31

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Balance Sheets

	June 30, 2010
	Denbury		Denbury
	Resources Inc.		Onshore, LLC
	(Parent and		(Issuer and			Guarantor			Non-Guarantor						Consolidated
In thousands	Co-Obligor)		Co-Obligor)			Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	1,741	$	25,456		$	25,573		$	14,704		$	—		$	67,474
Other current assets		170,846		206,382			927,305			33,005			(947,058	)		390,480
Total current assets		172,587		231,838			952,878			47,709			(947,058	)		457,954
Property and equipment:
Oil and natural gas properties (using full cost accounting):
Proved		—		3,980,060			2,078,281			776,335			—			6,834,676
Unevaluated		—		200,500			863,611			121,516			—			1,185,627
CO2 properties, equipment, and pipelines		—		1,388,524			316,176			—			—			1,704,700
Other		—		90,487			9,900			364			—			100,751
Less accumulated depletion, depreciation, amortization, and impairment		—		(1,960,557	)		(58,407	)		(14,972	)		—			(2,033,936	)
Net property and equipment		—		3,699,014			3,209,561			883,243			—			7,791,818
Other assets, net		1,907,387		243,535			103,902			18,109			(776,868	)		1,496,065
Investment in subsidiaries (equity method)		4,266,114		—			1,472,538			—			(5,738,652	)		—
Total assets	$	6,346,088	$	4,174,387		$	5,738,879		$	949,061		$	(7,462,578	)	$	9,745,837
LIABILITIES AND EQUITY
Current liabilities	$	52,306	$	953,012		$	503,218		$	27,273		$	(947,058	)	$	588,751
Long-term debt		1,983,541		475,864			—			245,000			—			2,704,405
Deferred taxes		—		600,456			932,653			780			(50,518	)		1,483,371
Other liabilities		—		809,537			36,894			17,751			(726,350	)		137,832
Total liabilities		2,035,847		2,838,869			1,472,765			290,804			(1,723,926	)		4,914,359
Total equity		4,310,241		1,335,518			4,266,114			658,257			(5,738,652	)		4,831,478
Total liabilities and equity	$	6,346,088	$	4,174,387		$	5,738,879		$	949,061		$	(7,462,578	)	$	9,745,837

	December 31, 2009
	Denbury		Denbury
	Resources Inc.		Onshore, LLC
	(Parent and		(Issuer and			Guarantor			Non-Guarantor					Consolidated
In thousands	Co-Obligor)		Co-Obligor)			Subsidiaries			Subsidiaries		Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	24	$	20,281		$	286		$	—	$	—		$	20,591
Other current assets		637,310		233,320			20,432			—		(655,891	)		235,171
Total current assets		637,334		253,601			20,718			—		(655,891	)		255,762
Property and equipment:
Oil and natural gas properties (using full cost accounting):
Proved		—		3,595,726			—			—		—			3,595,726
Unevaluated		—		320,356			—			—		—			320,356
CO2 properties, equipment, and pipelines		—		1,309,325			220,456			—		—			1,529,781
Other		—		82,185			352			—		—			82,537
Less accumulated depletion, depreciation, amortization and impairment		—		(1,825,282	)		(246	)		—		—			(1,825,528	)
Net property and equipment		—		3,482,310			220,562			—		—			3,702,872
Other assets, net		746,442		225,938			6,078			—		(742,131	)		236,327
Investment in subsidiaries (equity method)		1,303,728		23,792			1,299,186			—		(2,551,689	)		75,017
Total assets	$	2,687,504	$	3,985,641		$	1,546,544		$	—	$	(3,949,711	)	$	4,269,978
LIABILITIES AND EQUITY
Current liabilities	$	14,827	$	795,486		$	239,368		$	—	$	(655,891	)	$	393,790
Long-term debt		700,440		1,326,978			—			—		(726,350	)		1,301,068
Deferred taxes		—		527,849			3,448			—		(15,781	)		515,516
Other liabilities		—		87,367			—			—		—			87,367
Total liabilities		715,267		2,737,680			242,816			—		(1,398,022	)		2,297,741
Total equity		1,972,237		1,247,961			1,303,728			—		(2,551,689	)		1,972,237
Total liabilities and equity	$	2,687,504	$	3,985,641		$	1,546,544		$	—	$	(3,949,711	)	$	4,269,978

32

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations

	Three Months Ended June 30, 2010
	Denbury			Denbury
	Resources Inc.			Onshore, LLC
	(Parent and			(Issuer and			Guarantor			Non-Guarantor						Consolidated
In thousands	Co-Obligor)			Co-Obligor)			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues and other income:
Oil, natural gas, and related product sales	$	—		$	287,472		$	155,697		$	44,859		$	—		$	488,028
CO2 sales and transportation fees		—			4,690			—			—			—			4,690
Gain on sale of interests in Genesis		—			(67	)		39			—			—			(28	)
Interest income and other		16,243			2,808			821			666			(16,018	)		4,520
Total revenues		16,243			294,903			156,557			45,525			(16,018	)		497,210
Expenses:
Lease operating		—			90,475			26,792			10,476			—			127,743
Production taxes and marketing		—			12,605			20,817			4,678			—			38,100
CO2 operating		—			1,689			(8	)		—			—			1,681
General and administrative		205			24,008			3,436			3,543			—			31,192
Interest, net of amounts capitalized		51,795			16,070			(11,259	)		2,895			(16,018	)		43,483
Depletion, depreciation, and amortization		—			71,622			44,758			12,829			—			129,209
Derivative income		—			(82,212	)		(29,192	)		(17,270	)		—			(128,674	)
Transaction costs related to Encore Merger		—			2,125			20,659			—			—			22,784
Total expenses		52,000			136,382			76,003			17,151			(16,018	)		265,518
Equity in net earnings of subsidiaries		153,890			—			111,753			—			(265,643	)		—
Income before income taxes		118,133			158,521			192,307			28,374			(265,643	)		231,692
Income tax provision (benefit)		(13,917	)		62,808			32,233			239			—			81,363
Consolidated net income	$	132,050		$	95,713		$	160,074		$	28,135		$	(265,643	)	$	150,329

	Three Months Ended June 30, 2009
	Denbury			Denbury
	Resources Inc.			Onshore, LLC
	(Parent and			(Issuer and			Guarantor			Non-Guarantor					Consolidated
In thousands	Co-Obligor)			Co-Obligor)			Subsidiaries			Subsidiaries		Eliminations			Total
Revenues and other income:
Oil, natural gas, and related product sales	$	—		$	211,552		$	—		$	—	$	—		$	211,552
CO2 sales and transportation fees		—			2,884			—			—		—			2,884
Interest income and other		15,862			1,102			1,854			—		(15,862	)		2,956
Total revenues		15,862			215,538			1,854			—		(15,862	)		217,392
Expenses:
Lease operating		—			83,658			—			—		—			83,658
Production taxes and marketing		—			10,784			—			—		—			10,784
CO2 operating		—			1,095			—			—		—			1,095
General and administrative		—			29,056			4,079			—		—			33,135
Interest, net of amounts capitalized		17,339			15,147			(1,720	)		—		(15,862	)		14,904
Depletion, depreciation, and amortization		—			61,695			—			—		—			61,695
Derivative expense		—			152,789			—			—		—			152,789
Total expenses		17,339			354,224			2,359			—		(15,862	)		358,060
Equity in net earnings of subsidiaries		(85,763	)		—			(85,015	)		—		170,778			—
Loss before income taxes		(87,240	)		(138,686	)		(85,520	)		—		170,778			(140,668	)
Income tax provision (benefit)		—			(53,671	)		243			—		—			(53,428	)
Consolidated net loss	$	(87,240	)	$	(85,015	)	$	(85,763	)	$	—	$	170,778		$	(87,240	)

33

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations

	Six Months Ended June 30, 2010
	Denbury			Denbury
	Resources Inc.			Onshore, LLC
	(Parent and			(Issuer and			Guarantor			Non-Guarantor						Consolidated
In thousands	Co-Obligor)			Co-Obligor)			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues and other income:
Oil, natural gas, and related product sales	$	—		$	558,043		$	203,578		$	57,293		$	—		$	818,914
CO2 sales and transportation fees		—			9,187			—			—			—			9,187
Gain on sale of interests in Genesis		—			(227	)		101,767			—			—			101,540
Interest income and other		32,265			3,635			1,855			670			(32,035	)		6,390
Total revenues		32,265			570,638			307,200			57,963			(32,035	)		936,031
Expenses:
Lease operating		—			176,359			34,344			13,260			—			223,963
Production taxes and marketing		—			24,882			26,470			6,065			—			57,417
CO2 operating		—			3,049			—			—			—			3,049
General and administrative		323			50,691			8,663			4,224			—			63,901
Interest, net of amounts capitalized		85,623			30,014			(17,677	)		3,974			(32,035	)		69,899
Depletion, depreciation, and amortization		—			136,647			58,506			15,928			—			211,081
Derivative income		—			(113,850	)		(35,009	)		(21,040	)		—			(169,899	)
Transaction costs related to Encore Merger		—			45,934			20,911			938			—			67,783
Total expenses		85,946			353,726			96,208			23,349			(32,035	)		527,194
Equity in net earnings of subsidiaries		264,974			—			103,273			—			(368,247	)		—
Income before income taxes		211,293			216,912			314,265			34,614			(368,247	)		408,837
Income tax provision (benefit)		(20,961	)		129,679			49,334			252			—			158,304
Consolidated net income	$	232,254		$	87,233		$	264,931		$	34,362		$	(368,247	)	$	250,533

	Six Months Ended June 30, 2009
	Denbury			Denbury
	Resources Inc.			Onshore, LLC
	(Parent and			(Issuer and			Guarantor			Non-Guarantor					Consolidated
In thousands	Co-Obligor)			Co-Obligor)			Subsidiaries			Subsidiaries		Eliminations			Total
Revenues and other income:
Oil, natural gas, and related product sales	$	—		$	379,621		$	—		$	—	$	—		$	379,621
CO2 sales and transportation fees		—			6,049			—			—		—			6,049
Interest income and other		26,720			1,928			3,553			—		(26,720	)		5,481
Total revenues		26,720			387,598			3,553			—		(26,720	)		391,151
Expenses:
Lease operating		—			158,608			—			—		—			158,608
Production taxes and marketing		—			19,976			—			—		—			19,976
CO2 operating		—			2,395			—			—		—			2,395
General and administrative		—			47,962			7,828			—		—			55,790
Interest, net of amounts capitalized		28,971			27,323			(2,473	)		—		(26,720	)		27,101
Depletion, depreciation, and amortization		—			123,620			—			—		—			123,620
Derivative expense		—			173,304			—			—		—			173,304
Total expenses		28,971			553,188			5,355			—		(26,720	)		560,794
Equity in net earnings of subsidiaries		(103,286	)		—			(101,345	)		—		204,631			—
Loss before income taxes		(105,537	)		(165,590	)		(103,147	)		—		204,631			(169,643	)
Income tax provision (benefit)		—			(64,245	)		139			—		—			(64,106	)
Consolidated net loss	$	(105,537	)	$	(101,345	)	$	(103,286	)	$	—	$	204,631		$	(105,537	)

34

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2010
	Denbury			Denbury
	Resources Inc.			Onshore, LLC
	(Parent and			(Issuer and			Guarantor			Non-Guarantor						Consolidated
In thousands	Co-Obligor)			Co-Obligor)			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flow from operating activities:
Net cash provided by (used for) operating activities	$	(21,660	)	$	426,352		$	(539,831	)	$	41,856		$	477,574		$	384,291
Cash flow used for investing activities:
Oil and natural gas capital expenditures		—			(197,867	)		(117,241	)		(2,065	)		—			(317,173	)
Acquisitions of oil and natural gas properties		—			(23,951	)		(13	)		(279	)		—			(24,243	)
Cash paid in the Encore Merger, net of cash acquired		(830,310	)		—			15,705			13,116			—			(801,489	)
CO2 capital expenditures, including pipelines		—			(87,837	)		(64,614	)		—			—			(152,451	)
Net proceeds from sale of oil and natural gas properties and equipment		—			(2,658	)		884,002			—			—			881,344
Net proceeds from sale of interests in Genesis		—			23,537			139,085			—			—			162,622
Investments in subsidiaries (equity method)		501,025			—			(23,732	)		—			(477,293	)		—
Other		—			(7,102	)		(122	)		—			—			(7,224	)
Net cash provided by (used for) investing activities		(329,285	)		(295,878	)		833,070			10,772			(477,293	)		(258,614	)
Cash flow from financing activities:
Bank repayments		(879,000	)		(350,000	)		(265,000	)		(20,000	)		—			(1,514,000	)
Bank borrowings		919,000			225,000			—			5,000			—			1,149,000
Senior subordinated notes tendered post Encore Merger		(616,638	)		—			—			—			—			(616,638	)
Net proceeds from issuance of senior subordinated debt		1,000,000			—			—			—			—			1,000,000
Costs of debt financing		(76,232	)		—			—			—			—			(76,232	)
Other		5,532			(299	)		(2,952	)		(22,924	)		(281	)		(20,924	)
Net cash provided by (used for) financing activities		352,662			(125,299	)		(267,952	)		(37,924	)		(281	)		(78,794	)
Net increase in cash and cash equivalents		1,717			5,175			25,287			14,704			—			46,883
Cash and cash equivalents at beginning of period		24			20,281			286			—			—			20,591
Cash and cash equivalents at end of period	$	1,741		$	25,456		$	25,573		$	14,704		$	—		$	67,474

	Six Months Ended June 30, 2009
	Denbury			Denbury
	Resources Inc.			Onshore, LLC
	(Parent and			(Issuer and			Guarantor		Non-Guarantor					Consolidated
In thousands	Co-Obligor)			Co-Obligor)			Subsidiaries		Subsidiaries		Eliminations			Total
Cash flow from operating activities:
Net cash provided by operating activities	$	—		$	260,548		$	241	$	—	$	—		$	260,789
Cash flow used for investing activities:
Oil and natural gas capital expenditures		—			(215,978	)		—		—		—			(215,978	)
Acquisitions of oil and natural gas properties		—			(196,274	)		—		—		—			(196,274	)
CO2 capital expenditures, including pipelines		—			(399,406	)		—		—		—			(399,406	)
Net proceeds from sales of oil and gas properties and equipment		—			240,087			—		—		—			240,087
Investments in subsidiaries (equity method)		(388,391	)		5,115			—		—		388,391			5,115
Other		—			(8,384	)		—		—		—			(8,384	)
Net cash used for investing activities		(388,391	)		(574,840	)		—		—		388,391			(574,840	)
Cash flow from financing activities:
Bank repayments		—			(505,000	)		—		—		—			(505,000	)
Bank borrowings		—			475,000			—		—		—			475,000
Net proceeds from issuance of senior subordinated debt		389,827			389,827			—		—		(389,827	)		389,827
Net equity contributions		7,684			7,684			—		—		(7,684	)		7,684
Other		(9,120	)		(10,570	)		—		—		9,120			(10,570	)
Net cash provided by financing activities		388,391			356,941			—		—		(388,391	)		356,941
Net increase in cash and cash equivalents		—			42,649			241		—		—			42,890
Cash and cash equivalents at beginning of period		24			16,898			147		—		—			17,069
Cash and cash equivalents at end of period	$	24		$	59,547		$	388	$	—	$	—		$	59,959

Note 12. Encore Energy Partners LP

Administrative Services Agreement

     ENP does not have any employees. The employees supporting ENP’s operations are employees of Denbury. Encore Operating, L.P. (“Encore Operating”), a subsidiary of Denbury, performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

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Notes to Unaudited Condensed Consolidated Financial Statements

     From March 9, 2010 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production. Effective April 1, 2010, the administrative fee increased to $2.06 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment which occurs every April 1^st. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if ENP acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of GP LLC upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and GP LLC, with the approval of the conflicts committee of the board of directors of GP LLC.

     ENP reimburses Denbury for any state, income, franchise, or similar tax incurred by Denbury resulting from the inclusion of ENP in consolidated tax returns with Denbury as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP would have incurred had they not been included in a combined group with Denbury.

Note 13. Subsequent Events

     On July 29, 2010, the board of directors of GP LLC declared an ENP cash distribution for the second quarter of 2010 to unitholders of record as of the close of business on August 9, 2010 of $0.50 per unit or approximately $22.9 million of which $10.7 million is expected to be paid to GP LLC and its affiliates. The distribution is expected to be paid to unitholders on or about August 13, 2010.

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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, 2009, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

     We are a growing independent oil and natural gas company. We are the largest oil and natural gas operator 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 Rockies, Permian Basin and Gulf Coast regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling, and proven engineering extraction practices, with our most significant emphasis relating to tertiary recovery operations.

     During the first six months of 2010, we completed several strategic initiatives and achieved several milestones as follows:

• Recognized proved reserve additions totaling 65.4 MMBbls, excluding price revisions, during the second quarter;

• Completed construction of our Green Pipeline to Oyster Bayou Field with first CO₂ injection commencing in June 2010;

• Closed the sale of our Southern Assets (acquired in the Encore Merger) in May 2010;

• Closed the Encore Merger in March 2010; and

• Sold our interests in Genesis in February 2010.

     Details of these items are discussed below.

     Second Quarter Operating Highlights.The acquisition of Encore in March 2010 (“Encore Merger”) has had a significant impact on nearly every aspect of our business, including oil and natural gas production, revenues and operating expenses, which is more fully discussed throughout our discussion and analysis of financial condition and results of operations below. We recognized net income of $135.4 million, or $0.34 per basic common share, during the second quarter of 2010 as compared to a net loss of $87.2 million, or $0.35 per basic common share, in the second quarter of 2009. The increase in net income between the periods is primarily due to non-cash fair value changes of our commodity derivative contracts, a 61% increase in production volumes, and a 20% increase in realized prices (including derivative settlements), partially offset by an increase in operating expenses due to the additional properties recently acquired in the Encore Merger and higher overhead costs, including interest and Encore Merger-related expenses.

     During the second quarter of 2010, our oil and natural gas production averaged 84,111 BOE/d compared to 52,269 BOE/d produced in the second quarter of 2009. The production increases over levels in the prior year quarter are attributable to (1) the March 2010 Encore Merger, which contributed average production of 39,636 BOE/d in the second quarter, (2) tertiary production which increased 4,415 Bbls/d, and (3) the December 2009 acquisition of the Conroe field which contributed average production of 2,808 BOE/d in the second quarter of 2010. Offsetting these production increases was a decrease of 13,404 BOE/d due to the 2009 sale of our Barnett Shale properties. During the quarter, we sold certain oil and natural gas properties acquired in the Encore Merger (the “Southern Assets”), which closed on May 14, 2010. Excluding the production attributed to assets sold in both the 2009 and 2010 periods, our adjusted second quarter 2010 production was 78,545 BOE/d (adjusted to exclude the Southern Assets) an increase of 102% over the adjusted second quarter 2009 production levels (adjusted to exclude

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the Barnett Shale properties). See “— Sale of Southern Assets” and “Results of Operations — Operating Results — Production” for more information.

     Tertiary oil production averaged 28,507 Bbls/d during the second quarter of 2010, representing an 18% increase over our average tertiary oil production of 24,092 Bbls/d during the second quarter of 2009. We had strong production increases during the second quarter of 2010 from several of our existing tertiary oil fields, including production from Tinsley Field, which increased more than 54% between the comparable periods, and Delhi Field, our newest tertiary flood, which added an average of 648 Bbls/d of production. Please read “Results of Operations — CO₂ Operations” for more information.

     Oil prices trended slightly downward during the second quarter of 2010 as compared to prices in the first quarter of 2010, but oil prices were significantly higher in the second quarter of 2010 as compared to levels in the prior year second quarter. Our average oil and natural gas revenues per BOE, excluding the impact of commodity derivative contracts, was $63.76 per BOE in the second quarter of 2010, as compared to $44.48 per BOE in the second quarter of 2009, a 43% increase between the two periods. The increase in commodity prices increased our oil and natural gas revenues during the second quarter of 2010 by 70% as compared to levels in the second quarter of 2009. However, our average oil and natural gas revenues per BOE (including commodity derivative contracts) was $64.13 per BOE in the second quarter of 2010, compared to $53.31 per BOE during the second quarter of 2009, a 20% increase.

     Net cash settlements received on our commodity derivative contracts during the second quarter of 2010 were $2.8 million, compared to $42.0 million of cash settlements received during the second quarter of 2009. During the second quarter of 2010, we had a non-cash fair value gain on our commodity derivative contracts of $125.2 million, compared to a non-cash fair value loss of $194.8 million in the second quarter of 2009. Coupled together, all the adjustments on commodity derivative contracts increased our pretax income by $280.8 million in the second quarter of 2010 as compared to the levels of those items in the second quarter of 2009.

     Our lease operating expenses increased 53% in the second quarter of 2010 on an absolute basis, but decreased 5% on a per BOE basis. The increase on an absolute basis is primarily due to the March 2010 Encore Merger and further expansion of our tertiary operations, partially offset by the mid-2009 sale of the Barnett Shale properties. When comparing the second quarters of 2010 and 2009, the largest increases in lease operating expenses (excluding the increases associated with the Encore Merger) were related to CO₂ expense and power and utilities, all as a result of the expansion of our tertiary operations. The overall decrease on a BOE basis was primarily due to properties acquired in the Encore Merger, which had a lower overall operating cost per BOE. On a per BOE basis, our tertiary operating expense averaged $21.37 per BOE in the second quarter of 2010, as compared to $20.86 per BOE in the prior year second quarter and $22.67 per BOE in the first quarter of 2010.

     General and administrative (“G&A”) expenses totaled $31.2 million in the second quarter of 2010, compared to $33.1 million in the prior year quarter. When comparing the two quarters, the incremental administrative expense from the ownership of Encore incurred during the second quarter of 2010 was offset by the $10 million charge in the prior year quarter associated with the Founder Retirement Agreement entered into between Denbury and Gareth Roberts in connection with his retirement as CEO and President of Denbury. During the quarter, we incurred $22.8 million of transaction costs associated with the Encore Merger, primarily associated with employee severance, legal, and other professional fees. These Encore Merger-related fees are included in our income statement under the caption “Transaction costs related to the Encore Merger.” Interest expense also increased during the second quarter of 2010, due primarily to our $1.0 billion issuance of 2020 Notes in February 2010, Encore debt assumed in the Encore Merger, and borrowings under our new $1.6 billion revolving credit agreement used to finance a portion of the Encore Merger, offset in part by increased interest capitalization related to our CO₂ pipelines under construction.

     Addition of Proved Oil and Natural Gas Reserves.We added 65.4 MMBOE of proved reserves this quarter, before price revisions. These reserve additions consisted of 30.0 MMBbls of estimated proved tertiary reserves at Delhi Field, 6.9 MMBbls of other proved tertiary oil reserves, 15.2 MMBOE of estimated proved reserves at our Bakken properties (where we have recently reevaluated future reserve potential), and 12.0 MMBOE at Haynesville Field more than replacing the reserves attributable to the Southern Assets sold on May 14, 2010 (54 MMBOE, 64% natural gas). After considering

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production and the sale of the Southern Assets, our estimated total proved reserves at June 30, 2010 are approximately the same as our pro forma proved reserves (giving effect to Encore’s proved reserves) at December 31, 2009 of 427.8 MMBOE.

     Completion of Green Pipeline to Oyster Bayou.On June 29, 2010, Denbury placed the first phase (approximately 260 miles) of the Green Pipeline, a 320-mile CO₂ pipeline that runs from southern Louisiana to near Houston, Texas, in service. This phase runs to Denbury’s Oyster Bayou Field in Southeast Texas while the remaining portion, scheduled for completion in 2011, will service Denbury’s Hastings field west of Galveston Bay. The Green pipeline is designed to transport both natural and anthropogenic CO₂ and will ultimately service other tertiary operations along the Gulf Coast.

     Sale of Southern Assets.On May 14, 2010, we sold oil and natural gas properties and related assets, primarily located in the Permian Basin in West Texas and southeastern New Mexico; the Mid-continent area, which includes the Anadarko Basin in Oklahoma, Texas, and Kansas; and the East Texas Basin (the “Southern Assets”) to Quantum Resources Management, LLC for consideration of $883.9 million after closing adjustments and including a prior $45 million deposit. The properties acquired in the Encore Merger in the southern part of the United States which were not sold include our Haynesville Shale, Paradox Basin, Cleveland Sand Play, and Tuscaloosa Marine Shale properties. Production attributable to the properties sold was approximately 13,000 BOE/d (approximately 67% natural gas) and the proved reserves attributable to sold assets was approximately 54 MMBOE (64% natural gas). We used the proceeds from the divestiture to repay most of the outstanding borrowings under our revolving credit agreement.

     Merger with Encore Acquisition Company.On March 9, 2010, we acquired Encore pursuant to an Agreement and Plan of Merger (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 $4.5 billion at that time, including the assumption of debt and the value of the noncontrolling interest in ENP. Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger. The Encore Merger was consummated on March 9, 2010.

     Encore shareholders received the following consideration for each share of Encore common stock they owned, depending upon the elections, if any, which they made, and the collar, proration, and allocation features of the Encore Merger Agreement so that, in the aggregate, 30% of the consideration for the outstanding shares of Encore common stock would consist of cash, and the remaining 70% of the consideration would consist of shares of Denbury common stock:

• Mixed cash/stock electing (or non-electing) Encore stockholders received $15.00 in cash and 2.4048 shares of our common stock;

• All-cash electing Encore stockholders received $46.48 in cash and 0.2417 shares of our common stock; and

• All-stock electing Encore stockholders (including those whose Encore restricted stock bonuses were converted into Denbury restricted stock) received 3.4354 shares of our common stock.

     All Encore stock options fully vested and their value was paid in cash. All Encore restricted stock vested and each holder had the opportunity to make the same elections as other holders of Encore common stock as described above, except for shares of Encore restricted stock granted during 2010 as a bonus pursuant to the 2009 Encore annual incentive program, which were converted into restricted shares of Denbury common stock.

     In the Encore Merger, we issued approximately 135.2 million shares of our common stock and paid approximately $833.9 million in cash to Encore stockholders. The Denbury shares issued to Encore stockholders represented approximately 34% of our common stock issued and outstanding immediately after the Encore Merger. The total fair value of the Denbury common stock issued to Encore stockholders pursuant to the Encore Merger was approximately $2.1 billion based upon Denbury’s closing price of $15.43 per share on March 9, 2010. Please read “Note 3. Acquisitions and Divestitures” for additional information.

     The Encore Merger was financed through a combination of $1.0 billion of 8.25% Senior Subordinated Notes due 2020, (the “2020 Notes”), which we issued on February 10, 2010, the new $1.6 billion revolving credit agreement entered into on March 9, 2010, and the assumption of Encore’s remaining outstanding senior subordinated notes.

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     Subordinated Debt Issuance.On February 10, 2010, we issued 2020 Notes for net proceeds (after underwriting discounts and commissions) of $980 million. The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par. Upon the closing of the Encore Merger, $400 million of the net proceeds were used to finance a portion of the Encore Merger consideration. In March and April 2010, $580 million was used to fund repurchases of portions of Encore’s outstanding senior subordinated notes during March and April 2010.

     Sale of Interests in Genesis.On February 5, 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis, to an affiliate of Quintana Capital Group L.P. for net proceeds of approximately $84 million, after giving effect to the change of control provision of the incentive compensation agreement with Genesis’ management under which we paid a total of $14.9 million. During February 2010, we recognized G&A expense of $1.1 million associated with the $14.9 million payment. The remainder of the payment had been previously accrued in our financial statements as of December 31, 2009. In March 2010, we sold all of our common units in Genesis in a secondary public offering for net proceeds of approximately $79 million. As a result, we no longer hold any interest in Genesis. We recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.

     Strategic Alternatives and Asset Transaction Processes for ENP.The Southern Assets sale discussed above includes most of the properties acquired from Encore that could have been potential dropdown candidates to ENP, given the nature of their reserves and production. As a result of the sale, they are no longer available for dropdowns. Most of our remaining assets require significant capital expenditures in order to recognize their potential value, and therefore would not be appropriate properties to dropdown to ENP. Consequently, on April 30, 2010, ENP and Denbury announced their intent to explore a broad range of strategic alternatives (“strategic process”) to enhance the value of ENP’s common units, including, but not limited to, those alternatives involving a possible merger, sale, or other transaction involving ENP, our interest in ENP’s general partner, or all or part of the ENP common units that we own. We and ENP also announced a process to explore a way to recognize the full potential value of potential CO₂ tertiary projects that are owned by ENP, the biggest of which is Elk Basin Field, and which require the substantial capital investment required for a tertiary flood (“asset process”). We are reviewing alternative structures or transactions which could be pursued by ENP, Denbury, or a combination of the two, to allow development of this field without diluting the value of ENP’s units or reducing the ENP’s distributions per unit. Although either or both of these processes may result in one or more transactions involving the Partnership, Denbury and/or a third party, there is no assurance that a review of strategic alternatives or consideration of an asset transaction will result in the proposal or completion of any transaction with acceptable terms.

Capital Resources and Liquidity

     We currently estimate our pro forma 2010 capital spending (including Encore’s $46 million of capital expenditures between January 1, 2010 and March 9, 2010) will be approximately $1.06 billion, excluding capitalized interest, acquisitions, and divestitures, and net of equipment leases, and also excluding the expenditures related to the Encore Merger. Our current 2010 capital budget includes the following:

• $413 million allocated for tertiary oil field expenditures;

• $193 million to be spent on our CO₂ pipelines;

• $200 million to drill or participate in drilling or refracing of 55 to 75 wells in the Bakken area of North Dakota;

• $115 million on drilling, completion and other development activities in our other areas;

• $65 million to drill and complete 6 to 8 operated wells and participate in 20 to 25 non-operated wells in the Haynesville and other East Texas fields; and

• $74 million to be spent in the Jackson Dome area.

     This estimate also assumes that we fund approximately $50 million of budgeted equipment purchases with operating leases, which is dependent upon securing acceptable financing. If we do not enter into a total of $50 million of operating leases during 2010, our net capital expenditures would increase in an equal amount, and we would anticipate funding those additional capital expenditures under our bank credit line.

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

     As discussed above in “Overview — Merger with Encore Acquisition Company,” the primary sources of cash for the Encore Merger included a new $1.6 billion revolving credit agreement, which replaced our previously existing $750 million commitment from banks under our prior revolving credit agreement, and $1.0 billion of new 2020 Notes. We structured the financing of the Encore Merger to provide $600 million to $700 million of availability on our new $1.6 billion revolving credit agreement upon closing the transaction in order to provide a level of liquidity similar to that available to us prior to the Encore Merger. With the proceeds from the Southern Asset sale, we paid off nearly all of our bank debt and now have nearly the full $1.6 billion credit line available to us. These funds are available for the capital expenditures discussed above or any possible acquisitions, which amounts should be sufficient to cover capital expenditures in excess of cash flow from operations and provide additional liquidity.

     During 2009 and the first half of 2010, we also entered into oil derivative contracts through 2011 in order to protect our future cash flows. Please read Notes 6 and 7 to the Unaudited Condensed Consolidated Financial Statements for further details regarding our commodity derivative contracts.

     Based on oil and natural gas commodity futures prices in early August 2010 and our current estimated production forecasts, and before any asset sales or acquisitions, our pro forma 2010 capital budget (including Encore’s $46 million of capital expenditures from January 1, 2010 through March 9, 2010) is expected to be $200 million to $300 million greater than our anticipated cash flow from operations assuming a full year of operations of the combined companies. This shortfall will be funded with borrowings under our bank credit facility, which have been substantially reduced already during the year from the cash generated from the sale of our interests in Genesis (see “Overview — Sale of Interests in Genesis”) and from the sale of the Southern Assets acquired from Encore (see “Overview — Sale of Southern Assets”). In addition, we could potentially receive additional sales proceeds during 2010 from either (i) a sale of all or part of our interest in ENP (see “Strategic Alternatives and Asset Transaction Processes for ENP” above) or (ii) the sale of the Haynesville assets acquired in the Encore Merger, which are still being marketed, or both. If either of these potential sales transactions is consummated, there would be minimal need, if any, to borrow funds during 2010 to fund our budgeted capital expenditure program. As of August 9, 2010, we had $40.0 million of bank debt outstanding on our $1.6 billion revolving credit agreement. This leaves us significant borrowing capacity to fund any shortfall.

     In addition to the sale of the Southern Assets, we have attempted to sell our Haynesville assets acquired in the Encore Merger, but to date, the prices offered have not been acceptable to us. Since these are not core assets for us, we may solicit offers for these assets from time to time in the future, depending in part on future natural gas prices. We are planning to repackage and remarket these assets in the near future. If any such offers were deemed acceptable and we sell these assets, our total sales proceeds from sale of properties acquired as part of the Encore Merger would be greater than our previously forecasted range of $500 million to $1.0 billion from these sales. Any such Haynesville asset proceeds would be used to retire any existing bank debt at that time or used for general working capital needs.

     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 2010, we have contracted for certain capital expenditures, including construction of the second phase of the Green Pipeline already in progress and several drilling rigs, and therefore we cannot eliminate all of our capital commitments without penalties (refer to “Off-Balance Sheet Arrangements — Commitments and Obligations” for further information regarding these commitments).

Sources and Uses of Capital Resources

Capital Expenditure Summary

     The following table of capital expenditures includes accrued capital for each period. Our cash expenditures were $46.2 million lower in the 2010 period and $41.6 million higher in the 2009 period than the amounts listed below due to the change in our capital accruals in those periods:

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

	Six Months Ended
	June 30,
In thousands	2010		2009
Oil and natural gas exploration and development:
Drilling	$	155,503	$	28,960
Geological, geophysical, and acreage		15,121		7,198
Facilities		73,712		111,599
Recompletions		91,534		35,591
Capitalized interest		13,681		6,836
Total oil and natural gas exploration and development expenditures		349,551		190,184
Oil and natural gas property acquisitions		24,243		196,274
Fair value assigned to oil and natural gas properties acquired from Encore		5,626,268		—
Total oil and natural gas capital expenditures		6,000,062		386,458
CO2 capital expenditures:
CO2 pipelines		96,477		340,143
Fair value assigned to CO2 assets acquired from Encore		7,254		—
CO2 producing fields		39,667		22,453
Capitalized interest		31,481		20,991
Total CO2 capital expenditures		174,879		383,587
Total	$	6,174,941	$	770,045

     The amounts shown above for the Encore Merger include approximately $2.1 billion of our common stock issued to Encore stockholders in the Encore Merger, based upon 135.2 million shares valued at the closing price of $15.43 per share on March 9, 2010, and approximately $1.1 billion of the total Encore Merger consideration which was assigned to goodwill. Please read Note 3 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding the Encore Merger.

     Our capital expenditures for the first half of 2010, excluding the Encore Merger, were funded with $384.3 million of cash flow from operations along with proceeds from the sale of our interests in Genesis and our Southern Assets. See “Overview — Merger with Encore Acquisition Company” for a discussion of the financing of the Encore Merger. Our capital expenditures for the first half of 2009 were funded with $260.8 million of cash flow from operations, $197.5 million of net proceeds from the sale of a portion of our Barnett Shale natural gas assets, and $381.4 million of proceeds from the February 2009 issuance of the 9.75% Senior Subordinated Notes.

Off-Balance Sheet Arrangements

Commitments and Obligations

     Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in our proved reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Notes 6 and 7 to the Unaudited Condensed Consolidated Financial Statements.

     In conjunction with the Encore Merger, we acquired certain of Encore’s commitments associated with our acquisition of Encore, including: senior subordinated notes, derivative contracts, operating leases, and asset retirement obligations. The Encore Merger is discussed in Note 3 to the Unaudited Condensed Consolidated Financial Statements, asset retirement obligations are discussed in Note 4 to the Unaudited Condensed Consolidated Financial Statements, long-term debt is discussed in Note 5 to the Unaudited Condensed Consolidated Financial Statements, and derivative contracts are discussed in Notes 6 and 7 to the Unaudited Condensed Consolidated Financial Statements. Operating leases assumed in the Encore Merger require payments of approximately $2.0 million in the remainder of 2010, $7.0 million in 2011 through 2012, and

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

$2.6 million in 2013. In addition, we have entered into a new lease for our corporate headquarters with a 12-year term that has total minimum monthly payments which aggregate approximately $55.6 million. Please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the section entitled “Off-Balance Sheet Arrangements — Commitments and Obligations” contained in our Annual Report on Form 10-K for the year ended December 31, 2009 for further information regarding our commitments and obligations.

Results of Operations

CO₂ Operations

     Our focus on CO₂operations is becoming an ever-increasing part of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO₂, and we have outlined certain of this potential in our Annual Report on Form 10-K for the year ended December 31, 2009 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, 2009 for further information regarding these matters.

     We recognized CO₂ reserve additions of approximately 358 Bcf this quarter at Jackson Dome. During the second quarter of 2010, we spudded two additional CO₂ source wells at Jackson Dome in the Gluckstadt field to further increase our production capacity and potentially increase our proved CO₂ reserves. We estimated that we are currently capable of producing between 900 MMcf/d and 1 Bcf/d of CO₂. During the second quarter of 2010, our CO₂ production averaged 768 MMcf/d as compared to an average of 581 MMcf/d produced during the second quarter of 2009 and 802 MMcf/d produced in the first quarter of 2010. We used 86% of this production, or 659 MMcf/d, in our tertiary operations during the second quarter of 2010, and sold the balance to our industrial customers, or to Genesis pursuant to our volumetric production payments. Our CO₂ production at Jackson Dome was lower this quarter compared to levels in the first quarter of 2010 because our need for CO₂ at our tertiary properties was slightly less at certain fields. During June 2010, we placed in service the first phase (approximately 260 miles) of the Green Pipeline, a 320-mile CO₂ pipeline that runs from southern Louisiana to near Houston, Texas. This first phase runs to our Oyster Bayou field in Southeast Texas. We filled this pipeline with CO₂ from our source at Jackson Dome during June and commenced first injection of CO₂ at the Oyster Bayou field on June 29, 2010. Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2009 for further discussion on our CO₂ delivery obligations.

     We spent approximately $0.21 per Mcf in operating expenses to produce our CO₂ during the first six months of 2010, comprised of $0.20 per Mcf during the first quarter of 2010 and $0.22 per Mcf during the second quarter of 2010. This rate is up significantly from our $0.16 per Mcf cost during the first six months of 2009, due primarily to increased CO₂ royalty expense as a result of higher oil prices. Our estimated total cost per Mcf of CO₂ during the first six months of 2010 was approximately $0.31 per Mcf, after inclusion of depletion, depreciation, and amortization (“DD&A”) expense, up from the first six months of 2009 average of $0.24 per Mcf. Our estimated total cost per Mcf of CO₂ during the second quarter of 2010 was approximately $0.32 per Mcf, after inclusion of DD&A expense.

     The following table summarizes our tertiary oil production and tertiary lease operating expense per Bbl for each quarter in 2009 and the first and second quarters of 2010:

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	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Second
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Tertiary Oil Field	2009		2009		2009		2009		2010		2010
Phase 1:
Brookhaven		3,451		3,466		3,397		3,350		3,416		3,277
Little Creek area		1,619		1,560		1,356		1,479		1,690		1,971
Mallalieu area		4,490		4,264		3,679		4,005		3,443		3,628
McComb area		2,246		2,429		2,473		2,412		2,289		2,160
Lockhart Crossing		607		698		882		1,025		1,127		1,311
Phase 2:
Eucutta		3,813		4,145		4,068		3,912		3,792		3,625
Heidelberg		—		250		829		1,506		1,708		1,857
Martinville		1,118		951		720		724		927		764
Soso		2,705		2,589		2,813		3,224		3,213		3,207
Phase 3:
Tinsley		2,390		3,402		3,558		3,942		4,419		5,248
Phase 4:
Cranfield		144		338		572		728		936		811
Phase 5:
Delhi		—		—		—		—		63		648
Total tertiary oil production		22,583		24,092		24,347		26,307		27,023		28,507
Tertiary operating expense per Bbl	$	20.48	$	20.86	$	23.14	$	22.03	$	22.67	$	21.37

     Oil production from our tertiary operations increased to an average of 28,507 Bbls/d in the second quarter of 2010, an 18% increase over our second quarter of 2009 tertiary production level of 24,092 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods in our Tinsley, Heidelberg, Delhi, Soso, Cranfield, and Lockhart Crossing Fields. The Tinsley Field has been one of our top performing tertiary oil fields, and production there is expected to increase further as we continue to expand the flood. We initiated CO₂ injections at the Delhi Field (Phase 5) during November 2009 and saw initial tertiary production response at the Delhi Field late in the first quarter of 2010. During the second quarter, production there averaged 648 Bbls/d and we expect this production to continue to increase as we expand this CO₂ flood. Although we commenced injection of CO₂ into Oyster Bayou Field near the end of June 2010, we do not anticipate a production response from this field until late 2011.

     During the second quarter of 2010, operating costs for our tertiary properties averaged $21.37 per Bbl, higher than the second quarter of 2009 average cost of $20.86 per Bbl, primarily due to the higher cost of CO₂. On a per Bbl basis, our cost of CO₂ increased by $1.37 per Bbl, from $3.68 per Bbl in the second quarter of 2009 to $5.05 per Bbl in the second quarter of 2010, primarily due to the increase in oil prices to which our CO₂ costs are partially tied. The single highest cost for our tertiary operations is our cost for fuel and utilities, which averaged $5.72 per Bbl in the second quarter of 2009 and $5.82 per Bbl in the second quarter of 2010. For any specific field, we expect our tertiary lease operating expense per Bbl to be high initially, then decrease as production increases, ultimately leveling off until production begins to decline in the latter life of the field, when lease operating expense per Bbl will again increase.

Operating Results

     As summarized in the “Overview” section above, and discussed in further detail below, our operating results for the second quarter and first six months of 2010 were significantly higher than results in the same periods in 2009. The operating results of Encore and ENP from March 9, 2010 through June 30, 2010 are included in these results. As we control the general partner of ENP, the operating results of ENP are consolidated with our results of

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DENBURY RESOURCES INC.

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

operations from our legacy properties, even though we only own approximately 46% of ENP’s common units. The primary factors impacting our operating results were the acquisition of Encore, higher oil and natural gas prices, changes in the fair value of our commodity derivative contracts, the gain on the sale of our interests in Genesis, and changes in production, which are all explained in more detail below.

     Certain of our operating results and statistics for the comparative second quarters and first six months of 2010 and 2009 are included in the following table:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per share and unit data	2010			2009			2010(1)			2009
Operating results:
Net income (loss) attributable to Denbury stockholders	$	135,367		$	(87,240	)	$	232,255		$	(105,537	)
Net income (loss) per common share — basic		0.34			(0.35	)		0.67			(0.43	)
Net income (loss) per common share — diluted		0.34			(0.35	)		0.66			(0.43	)
Cash flow from operations		271,123			148,170			384,291			260,789
Average daily production volumes:
Bbls/d		65,942			37,921			55,185			37,781
Mcf/d		109,014			86,088			81,108			90,327
BOE/d		84,111			52,269			68,703			52,836
Operating revenues:
Oil sales	$	443,984		$	188,170		$	749,188		$	321,435
Natural gas sales		44,044			23,382			69,726			58,186
Total oil and natural gas sales	$	488,028		$	211,552		$	818,914		$	379,621
Commodity derivative contracts: (2)
Cash receipt (payment) on settlement of commodity derivative contracts	$	2,801		$	42,002		$	(57,000	)	$	127,838
Non-cash fair value adjustment income (expense)		125,190			(194,791	)		226,029			(301,142	)
Total income (expense) from commodity derivative contracts	$	127,991		$	(152,789	)	$	169,029		$	(173,304	)
Operating expenses:
Lease operating	$	127,743		$	83,658		$	223,963		$	158,608
Production taxes and marketing		38,100			10,784			57,417			19,976
Total production expenses	$	165,843		$	94,442		$	281,380		$	178,584
Non-tertiary CO2 operating margin:
CO2 sales and transportation fees	$	4,690		$	2,884		$	9,187		$	6,049
CO2 operating expenses		(1,681	)		(1,095	)		(3,049	)		(2,395	)
Non-tertiary CO2 operating margin	$	3,009		$	1,789		$	6,138		$	3,654
Unit prices — including impact of derivative settlements: (2)
Oil price per Bbl	$	71.68		$	66.70		$	67.26		$	65.70
Natural gas price per Mcf		6.12			2.98			6.14			3.56
Unit prices — excluding impact of derivative settlements: (2)
Oil price per Bbl	$	73.99		$	54.53		$	75.00		$	47.00
Natural gas price per Mcf		4.44			2.98			4.75			3.56
Oil and natural gas operating revenues and expenses per BOE:
Oil and natural gas revenues	$	63.76		$	44.48		$	65.85		$	39.70
Oil and natural gas lease operating expenses	$	16.69		$	17.59		$	18.01		$	16.59
Oil and natural gas production taxes and marketing expense		4.98			2.27			4.62			2.09
Total oil and natural gas production expenses	$	21.67		$	19.86		$	22.63		$	18.68

(1)	Includes the results of operations of Encore and ENP from March 9, 2010 through June 30, 2010.
(2)	Please read “Item 3. Qualitative and Quantitative Disclosures about Market Risk” for additional information concerning our commodity derivative contracts.

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DENBURY RESOURCES INC.

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

     Production.Average daily production by area for each of the four quarters of 2009 and for the first and second quarters of 2010 are shown below, as well as our estimated pro forma production for the first quarter of 2010 had production from the properties acquired in the Encore Merger been included with ours for the entire first quarter of 2010:

	Average Daily Production (BOE/d)
	First		Second		Third		Fourth		First		Pro Forma		Second
	Quarter		Quarter		Quarter		Quarter		Quarter		First Quarter		Quarter
Operating Area	2009		2009		2009		2009		2010(1)		2010(2)		2010(3)
Tertiary oil fields		22,583		24,092		24,347		26,307		27,023		27,023		28,507
Mississippi — non-CO2 floods		11,904		10,043		8,931		8,914		7,829		7,829		8,967
Texas		17,063		16,088		7,579		8,035		5,235		5,235		5,148
Onshore Louisiana		708		885		699		679		662		662		775
Alabama and other		1,150		1,161		1,103		1,077		997		997		1,078
Cedar Creek Anticline		—		—		—		—		2,606		10,070		10,234
Bakken		—		—		—		—		893		3,560		4,518
Haynesville		—		—		—		—		838		3,196		3,931
Permian Basin		—		—		—		—		2,180		9,105		5,921
Other Rockies		—		—		—		—		2,429		9,411		9,459
Mid-Continent		—		—		—		—		2,433		9,490		5,573
Total		53,408		52,269		42,659		45,012		53,125		86,578		84,111

(1)	Includes production of Encore and ENP from March 9, 2010 through March 31, 2010. ENP’s production for each area during this period was as follows: Cedar Creek Anticline 69 BOE/d, Bakken 3 BOE/d, Permian Basin 852 BOE/d, Other Rockies 1,227 BOE/d, and Mid-Continent 120 BOE/d.
(2)	ENP’s pro forma production for each area during this period was as follows: Cedar Creek Anticline 240 BOE/d, Bakken 11 BOE/d, Permian Basin 3,411 BOE/d, Other Rockies 4,845 BOE/d, and Mid-Continent 527 BOE/d.
(3)	ENP’s production for each area during this period was as follows: Cedar Creek Anticline 267 BOE/d, Bakken 18 BOE/d, Permian Basin 3,268 BOE/d, Other Rockies 4,816 BOE/d, and Mid-Continent 473 BOE/d.

     As outlined in the above table, production in the three and six months ended June 30, 2010 increased 61% and 30%, respectively, over the respective 2009 production levels. These increases were primarily due to the additional production from the properties acquired in the Encore Merger, increased production in our tertiary fields, and the Conroe field acquisition which closed in December 2009. Offsetting these increases were two asset sales, the Barnett Shale sale which closed in the second half of 2009 and the Southern Assets sale which closed on May 14, 2010. Our continuing production excluding production from these sales was 78,545 BOE/d for the second quarter of 2010 as compared to 38,879 BOE/d for the second quarter of 2009, an increase of 102% (39,691 BOE/d). Production from our Bakken properties averaged 4,518 BOE/d, an increase of 27% as compared to pro forma first quarter 2010 assuming these properties acquired from Encore had been included for the entire quarter. The production increases in the Bakken are due to on-going drilling and hydraulic fracturing in this area. During the second quarter, we had three active rigs in the Bakken area, and we plan to secure a fourth drilling rig for the late third quarter or early fourth quarter of 2010. Our production at Cedar Creek Anticline averaged 10,234 BOE/d during the quarter, comparable to the pro forma production in the first quarter in this area while production at Haynesville increased 23% compared to pro forma production in the first quarter due to drilling activity.

     Our tertiary oil production in the three and six months ended June 30, 2010 increased 18% and 19%, respectively, over the respective 2009 production levels. The increase in our tertiary oil production is discussed above under “Results of Operations — CO₂ Operations.”

     Production in our Mississippi — non-tertiary operations decreased 11% and 23% from levels in the three and six months ended June 30, 2009, respectively, partially due to the expected gradual decline in the Heidelberg Field due to depletion, and the development of the Heidelberg CO₂ flood, which resulted in production being shut-in while portions of the field were converted to tertiary operations. When production commences from these CO₂ floods, these volumes will be reported as tertiary production for the Heidelberg Field. Another almost equal factor in the lower production in the three and six months ended June 30, 2010 was the lack of drilling activity in the Selma

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DENBURY RESOURCES INC.

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

Chalk, a natural gas asset characterized by relatively higher decline rates. The sequentially increased production of approximately 15% over first quarter 2010 levels in our Mississippi — non-tertiary operations is primarily due to a decrease in oil inventory from the first quarter and increased production at our Sharon field associated with three new drills.

     Our production during the three and six months ended June 30, 2010 was 78% and 80% oil, respectively, as compared to 73% and 72% during the three and six months ended June 30, 2009, respectively. This increase is due to the sale of our Barnett Shale properties in the second half of 2009, the acquisition of interests in the Hastings Field in February 2009, the acquisition of interests in the Conroe Field in December 2009, and the increase in our tertiary operations, partially offset by the natural gas properties which we acquired in the Encore Merger and sold in May 2010.

     Oil and Natural Gas Revenues.Due to the significant increase in oil and natural gas prices between the first half of 2009 and 2010, our oil and natural gas revenues increased sharply in the three and six months ended June 30, 2010 as compared to those in the same periods of 2009. These changes in oil and natural gas revenues, excluding any impact of our commodity derivative contracts, are reflected in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010 vs. 2009				2010 vs. 2009
			Percentage				Percentage
	Increase in		Increase in		Increase in		Increase in
In thousands	Revenues		Revenues		Revenues		Revenues
Change in oil and natural gas revenues due to:
Increase in commodity prices	$	147,600		70%	$	325,284		86%
Increase in production		128,876		61%		114,009		30%
Total increase in oil and natural gas revenues	$	276,476		131%	$	439,293		116%

     Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first and second quarters and first six month periods of 2010 and 2009:

	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
	2010			2009			2010			2009			2010			2009
Net Realized Prices:
Oil price per Bbl	$	76.53		$	39.34		$	73.99		$	54.53		$	75.00		$	47.00
Natural gas price per Mcf		5.40			4.09			4.44			2.98			4.75			3.56
Price per BOE		69.21			34.97			63.76			44.48			65.85			39.70
NYMEX Differentials:
Oil per Bbl	$	(2.08	)	$	(3.99	)	$	(4.13	)	$	(5.30	)	$	(3.36	)	$	(4.62	)
Natural gas per Mcf		0.37			(0.41	)		0.09			(0.82	)		0.06			(0.59	)

     Our oil NYMEX differential improved in the three and six months ended June 30, 2010 as compared to our differential in the comparable periods of 2009, primarily due to the 2009 sale of our Barnett Shale properties, where the NGL price was significantly below NYMEX oil prices, partially offset by the Rocky Mountain properties we acquired in the Encore Merger which tend to have higher oil differentials than our historical corporate average.

     Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be quite large, these differentials are very seldom more than a dollar above or below NYMEX prices.

47

DENBURY RESOURCES INC.

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

     Commodity Derivative Contracts.The following tables summarize the impact that our commodity derivative contracts had on our operating results for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June 30,												Six Months Ended June 30,
	2010			2009			2010			2009			2010			2009			2010		2009
	Oil Derivative						Natural Gas Derivative						Oil Derivative						Natural Gas Derivative
In thousands	Contracts						Contracts						Contracts						Contracts
Non-cash fair value gain (loss)	$	145,099		$	(189,318	)	$	(19,909	)	$	(5,473	)	$	206,920		$	(285,179	)	$	19,109	$	(15,963	)
Cash settlement receipts (payments)		(13,829	)		42,002			16,630			—			(77,379	)		127,838			20,379		—
Total	$	131,270		$	(147,316	)	$	(3,279	)	$	(5,473	)	$	129,541		$	(157,341	)	$	39,488	$	(15,963	)

     Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our commodity derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the changes in fair value of these contracts, as outlined above, are recognized currently in the income statement. Please read Notes 6 and 7 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

     Production Expenses.Our lease operating expenses increased between the three and six months ended June 30, 2010 and 2009 in absolute dollars but decreased on a per BOE basis. The overall decrease on a per BOE basis was primarily due to the Encore acquisition as those properties which were part of the Encore acquisition generally have a lower operating cost per BOE than Denbury’s legacy properties. The increase on an absolute basis was primarily a result of:

• the completion of the Encore Merger on March 9, 2010, which increased lease operating expense on an absolute basis, but reduced it on a per BOE basis;

• our increasing emphasis on tertiary operations and additional tertiary fields moving into the productive phase (please read discussion of those expenses under “CO₂ Operations”);

• the acquisition of interests in the Hastings Field in February 2009, which has a higher operating cost per BOE than most of our other properties;

• increased personnel and related costs resulting primarily from the Encore Merger;

• higher electrical costs to operate our properties due primarily to the expansion of our tertiary operations; and

• increasing lease payments due to incremental leasing of certain equipment in our tertiary operating facilities; partially offset by the sale of our Barnett Shale natural gas properties in the second half of 2009, which reduced lease operating expense on an absolute basis, but increased it on a per BOE basis as these properties had a lower per unit operating cost.

     Lease operating expense per BOE averaged $16.69 per BOE and $18.01 per BOE for the three and six months ended June 30, 2010, respectively, as compared to $17.59 per BOE and $16.59 per BOE for the same periods of 2009. Our tertiary operating costs, which have historically been higher than our company-wide operating costs, averaged $21.37 per BOE and $22.00 per BOE during the three and six months ended June 30, 2010, respectively, as compared to $20.86 per BOE and $20.68 per BOE for the same periods of 2009. Please read “CO₂ Operations” for a more detailed discussion. We expect that our operating cost on a per BOE basis will become closer to our tertiary operating costs as these operations become a larger percentage of our total operations. Costs of electricity and utilities to operate our tertiary properties have increased on an absolute basis primarily due to the expansion of our tertiary operations. We expect our tertiary operating costs to partially correlate with oil prices, as the price we pay for CO₂ is partially tied to oil prices.

     Production taxes and marketing expenses generally change in proportion to commodity prices and production volumes, and as such, increased 253% and 187% in the three and six months ended June 30, 2010, respectively, as compared to those for the same periods of 2009. This compares to an increase in oil and natural gas revenues of 131% and 116% in the three and six months ended June 30, 2010, respectively. The addition of properties in other operating areas acquired in the Encore Merger also affected these costs. Transportation and plant processing fees decreased approximately $1.8 million and $4.2 million in the three and six months ended June 30, 2010 and 2009, primarily due to the sale of our Barnett Shale properties in the second half of 2009.

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DENBURY RESOURCES INC.

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

General and Administrative Expenses

     G&A expenses decreased on both a gross basis and on a per BOE basis between the respective three months ended June 30, 2010 and 2009, while increasing on a gross basis, but decreasing on a per BOE basis between the respective six months ended June 30, 2010 and 2009 as set forth below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per BOE data and employees	2010			2009			2010			2009
Gross cash G&A expense	$	57,909		$	36,107		$	106,183		$	71,474
Gross stock-based compensation		7,363			6,359			16,153			12,499
Founder’s compensation award		—			10,000			—			10,000
Incentive compensation for Genesis management		—			2,945			1,149			5,538
State franchise taxes		965			1,124			2,035			2,239
Operator labor and overhead recovery charges		(29,086	)		(19,791	)		(51,131	)		(38,777	)
Capitalized exploration and development costs		(5,959	)		(3,609	)		(10,488	)		(7,183	)
Net G&A expense	$	31,192		$	33,135		$	63,901		$	55,790
G&A per BOE:
Net cash G&A expense	$	3.15		$	2.88		$	3.81		$	2.87
Net stock-based compensation		0.79			1.13			1.08			1.10
Founder’s compensation award		—			2.10			—			1.05
Incentive compensation for Genesis management		—			0.62			0.09			0.58
State franchise taxes		0.13			0.24			0.16			0.23
Net G&A expense	$	4.07		$	6.97		$	5.14		$	5.83
Employees as of June 30		1,304			859			1,304			859

     Gross cash G&A expenses increased $21.8 million (60%) and $34.7 million (49%), respectively, in the three and six months ended June 30, 2010, as compared to the same periods of 2009, primarily due to the Encore Merger and higher compensation and personnel-related costs associated with an increase in the number of employees and higher wages, which we consider necessary in order to remain competitive in our industry. During the three and six months ended June 30, 2010, we increased our employee count by 4% and 57%, primarily as a result of the Encore Merger, resulting in increased personnel-related costs. During the three and six months ended June 30, 2010, stock-based compensation expense increased $1.0 million and $3.7 million, respectively, when compared to levels in the same periods of 2009, primarily due to the increase in employees and changes in the mix of compensation awarded to employees.

     During the six months ended June 30, 2010, the increase in personnel-related costs was partially offset by a $4.4 million decrease in charges relating to incentive compensation awards for the management of Genesis. As discussed above under “Overview — Sale of Interests in Genesis,” we sold our interests in Genesis during the first quarter of 2010. As such, the change of control provision of each member’s compensation agreement was triggered and the incentive compensation awards were settled for $14.9 million, with $1.1 million of this being recognized as expense during February 2010.

     In addition to the decrease in expense related to Genesis incentive compensation awards, G&A expense for the 2010 periods also decreased $10 million because the 2009 period included the Founder’s Compensation Award issued June 30, 2009 in association with the retirement of Gareth Roberts as President and CEO of the Company.

     The increase in gross G&A expense in the three and six months ended June 30, 2010, as compared to those costs in the same period of 2009, was offset in part by an increase in operator overhead recovery charges. Our well

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DENBURY RESOURCES INC.

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

operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. Operator labor and overhead recovery charges also include $1.8 million received from Quantum in payment for our continuing to operate the Southern Asset properties through July 2010. As a result of additional operated wells from acquisitions, additional tertiary operations, drilling activity during the past year, and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 47% and 32%, respectively, in the three and six months ended June 30, 2010, as compared to the same period of 2009. Capitalized exploration and development costs also increased between the periods, primarily due to additional personnel and increased compensation costs.

     The net effect of these changes resulted in a 6% decrease (42% on a per BOE basis) in G&A expense between the comparable second quarters of 2010 and 2009. For the six month periods, G&A expenses increased 15% on a gross basis, but decreased 12% on a per BOE basis, as our increased production for the six month period more than offset the increase in expenses.

Interest and Financing Expenses

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per BOE data and interest rates	2010			2009			2010			2009
Cash interest expense	$	60,966		$	28,318		$	105,940		$	51,602
Non-cash interest expense		6,367			2,040			9,121			3,326
Less: capitalized interest		(23,850	)		(15,454	)		(45,162	)		(27,827	)
Interest expense	$	43,483		$	14,904		$	69,899		$	27,101
Interest income and other	$	4,520		$	2,956		$	6,390		$	5,481
Net cash interest expense and other income per BOE(1)	$	4.43		$	2.52		$	4.53		$	2.33
Average debt outstanding	$	3,152,564		$	1,363,007		$	2,689,894		$	1,249,030
Average interest rate(2)		7.7%			8.3%			7.9%			8.3%

(1)	Cash interest expense less capitalized interest less interest and other income on a per BOE basis.
(2)	Includes commitment fees but excludes debt issue costs and amortization of discount and premium.

     Interest expense increased $28.6 million (192%) and $42.8 million (158%), respectively, in the three and six months ended June 30, 2010, as compared to levels in the same periods of 2009, primarily due to our February 2010 issuance of the 2020 Notes, debt assumed from Encore in the Encore Merger, and borrowings under our new $1.6 billion revolving credit agreement, which were used to finance a portion of the Encore Merger. These increases were partially offset by a 54% and 62% increase in our interest capitalization for the three and six months ended June 30, 2010, as compared to the same periods of 2009, relating mainly to our CO₂ pipelines under construction. The first phase of our Green Pipeline was placed into service on June 29, 2010, and the balance of approximately $815 million (including capitalized interest) was no longer subject to interest capitalization at that date. A significant amount of our capitalized interest was related to the construction of this pipeline, and therefore in the near future our capitalized interest is expected to decline accordingly.

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DENBURY RESOURCES INC.

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

Depletion, Depreciation, and Amortization

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per BOE data	2010		2009		2010		2009
Depletion, depreciation, and amortization of oil and natural gas properties	$	116,034	$	53,504	$	187,231	$	106,955
Depletion and depreciation of CO2 assets		5,680		4,019		10,980		8,561
Asset retirement obligations		1,692		810		2,799		1,637
Depreciation of other fixed assets		5,803		3,362		10,071		6,467
Total DD&A	$	129,209	$	61,695	$	211,081	$	123,620
DD&A per BOE:
Oil and natural gas properties	$	15.38	$	11.42	$	15.28	$	11.36
CO2 assets and other fixed assets		1.50		1.55		1.69		1.57
Total DD&A cost per BOE	$	16.88	$	12.97	$	16.97	$	12.93

     Depletion of oil and natural gas properties increased on both a per BOE basis and in absolute dollars during the three and six months ended June 30, 2010 as compared to the same periods of 2009, primarily due to the increase in our oil and natural gas property balance and the associated reserve volumes and production from the Encore Merger, reserve additions in our tertiary fields and our Bakken properties during the second quarter of 2010, and the acquisition of interests in the Conroe Field in December 2009.

     We continually evaluate the performance of our tertiary projects, and if performance indicates that we are reasonably certain of recovering additional reserves from these floods, we recognize those incremental reserves in that quarter. Since we adjust our DD&A rate each quarter based on any changes in our estimates of oil and natural gas reserves and costs, our DD&A rate could change significantly in the future. We recognized incremental reserves during the second quarter of 2010 related to our tertiary production at Delhi Field and other tertiary fields, where we initiated CO₂ injections during the fourth quarter of 2009, and had first oil production response to tertiary injections during March 2010.

     Our DD&A expense for our other fixed assets increased on an absolute basis during the three and six month periods ended June 30, 2010 as compared to the comparable periods in 2009. The increase is primarily a result of the Encore Merger in March 2010 and field office expansion during 2009. Our DD&A expense for our CO₂ assets increased on an absolute basis for the three and six months ended June 30, 2010 compared to the prior periods primarily due to increased CO₂ production. On a BOE basis our CO₂ assets and other fixed assets decreased for the three months ended June 30, 2010 compared to the prior year quarter due to increased oil and natural gas production volumes as a result of the Encore Merger which closed in March 2010. The first phase of our Green Pipeline was placed into service on June 29, 2010, and became subject to depreciation. At June 30, 2010, we had $78.7 million of costs (including capitalized interest) related to CO₂ pipelines under construction, principally related to the remaining portion of the Green Pipeline to Hastings Field, which were not being depreciated. For financial accounting purposes, depreciation of these pipelines will commence as each pipeline is placed into service.

     During the second quarter, we closed on the sale of the Southern Assets. We did not record a gain in accordance with the full cost method of accounting. Instead, the proceeds from this sale were recorded as a reduction to the full cost pool.

     Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. We did not have a ceiling test write-down at June 30, 2010. However, if oil prices were to decrease significantly in subsequent periods, we may be required to record additional write-downs under the full cost pool ceiling test in the future. The possibility and amount of any future write-down is difficult to predict, and will depend upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures, and additional capital spent.

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

Encore Transaction Costs

     FASC “Business Combinations” topic requires that all transaction-related costs (advisory, legal, accounting, due diligence, integration, etc.) be expensed as incurred. We recognized a total of $22.8 million and $67.8 million, respectively, of transaction costs in the three and six months ended June 30, 2010 associated with the Encore Merger, including $19.5 million and $20.7 million, respectively, related to severance costs.

Income Taxes

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per BOE amounts and tax rates	2010			2009			2010			2009
Current income tax provision	$	6,941		$	24,127		$	7,610		$	24,300
Deferred income tax provision (benefit)		74,422			(77,555	)		150,694			(88,406	)
Total income tax provision (benefit)	$	81,363		$	(53,428	)	$	158,304		$	(64,106	)
Average income tax provision (benefit) per BOE	$	10.63		$	(11.23	)	$	12.73		$	(6.70	)
Effective tax rate		35.1	%		38.0	%		38.7	%		37.8	%

     Our income taxes are based on an estimated statutory rate of approximately 37.7%. Our effective tax rate has historically been slightly lower than our estimated statutory rate due to the impact of certain items such as our domestic production activities deduction, offset in part by certain non-cash stock-based compensation that cannot be deducted for tax purposes in the same manner as book expense. As a result of the Encore Merger, our statutory rate increased, which required us to remeasure our deferred tax liabilities in the first quarter of 2010 resulting in an additional income tax provision of approximately $10 million. As a result of the sale of the Southern Assets, our statutory rate decreased, which required us to remeasure our deferred tax liabilities in the second quarter of 2010 resulting in an income tax benefit of approximately $3 million. The combination of these items increased our effective tax rate to 38.7% during the six months ended June 30, 2010, as compared to 37.8% in the six months ended June 30, 2009.

     In the three and six months ended June 30, 2009, the current income tax expense represented our anticipated alternative minimum cash taxes that we could not offset with enhanced oil recovery credits. In addition, included in the second quarter of 2009 was approximately $16 million in current taxes associated with our sale of a portion of our Barnett Shale assets in June 2009. The current income tax expense for the three and six months ended June 30, 2010 represents state income taxes, primarily related to the sale of the Southern Assets and the sale of our interests in Genesis. As of June 30, 2010, we had an estimated $50.3 million of enhanced oil recovery credits, including $11.4 million related to the Encore Merger, to carry forward that can be utilized to reduce our current income taxes during 2010 or future years. These enhanced oil recovery credits do not begin to expire until 2023. Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.

     The Encore Merger was treated as a tax-free asset acquisition for tax purposes. Accordingly, Encore’s tax basis and tax attributes carried over to us, with the tax attributes being subject to certain limitations. Upon testing these limitations, it has been determined that the limitations do not affect our use of Encore’s tax attributes. The tax attributes that carried over to us include enhanced oil recovery credits of $11.4 million, alternative minimum tax credits of $2.3 million, and state net operating losses of $0.9 million, tax effected.

     In the second 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 which led us to apply for refunds of certain amounts related thereto on our 2004 and 2006 federal income tax returns. In the course of an IRS audit of those claims for refunds, the IRS examination team has questioned the change in accounting method and the ruling received from the National Office of the IRS in 2008. Together with the IRS, we have submitted a request to the National Office of the IRS for a Technical Advice Memorandum (TAM) regarding these issues, which is under consideration by the National Office. Although we have not recorded an uncertain tax position related to these deductions as we expect to receive those tax refunds, given the existence of

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

the TAM process related to those refunds, the payment of those tax refunds of approximately $10.6 million for tax years through 2006 is not free from doubt. Although this change to our method of tax accounting is not expected to have a significant impact on our overall tax rate, it is anticipated that it could defer the amount of cash taxes we might otherwise pay over the next several years.

Per BOE Data

     The following table summarizes our cash flow, DD&A, and results of operations on a per BOE basis for the comparative periods. Each of the individual components is discussed above.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Per BOE data	2010			2009			2010			2009
Oil and natural gas revenues	$	63.76		$	44.48		$	65.85		$	39.70
Settlement payments (receipts) of commodity derivative contracts		0.37			8.83			(4.58	)		13.36
Lease operating expenses		(16.69	)		(17.59	)		(18.01	)		(16.59	)
Production taxes and marketing expenses		(4.98	)		(2.27	)		(4.62	)		(2.09	)
Production netback		42.46			33.45			38.64			34.38
Non-tertiary CO2 operating margin		0.39			0.38			0.49			0.38
G&A expenses		(4.07	)		(6.97	)		(5.14	)		(5.83	)
Transactions costs related to the Encore Merger		(2.98	)		—			(5.45	)		—
Net cash interest expense and other income		(4.43	)		(2.52	)		(4.53	)		(2.33	)
Current income taxes and other		0.10			(1.59	)		0.66			(0.32	)
Changes in operating assets and liabilities		3.95			8.40			6.23			0.99
Cash flow from operations		35.42			31.15			30.90			27.27
DD&A		(16.88	)		(12.97	)		(16.97	)		(12.93	)
Deferred income taxes		(9.72	)		16.31			(12.12	)		9.24
Gain on sale of interests in Genesis		—			—			8.17			—
Non-cash fair value derivative adjustments		16.45			(40.95	)		18.25			(31.49	)
Net income attributable to noncontrolling interest		1.95			—			1.47			—
Changes in operating assets and liabilities and other non-cash items		(9.53	)		(11.88	)		(11.02	)		(3.13	)
Net income (loss) attributable to Denbury stockholders	$	17.69		$	(18.34	)	$	18.68		$	(11.04	)

Critical Accounting Policies

     For additional discussion of our critical accounting policies, which remain unchanged, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2009.

Forward-Looking Information

     The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods, acquisition plans and proposals and dispositions, development activities, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves, potential reserves from tertiary operations, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and natural gas prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans.

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

Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target,” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas; unexpected difficulties in integrating the operations of Denbury and Encore; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets; general economic conditions; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and natural gas drilling and production activities or which are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Long-Term Debt and Interest Rate Sensitivity

     We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. We had $285 million of bank debt outstanding as of June 30, 2010 (primarily ENP bank debt as outlined below), $135 million of which is subject to floating interest rates after taking into consideration interest rate swaps. The carrying value of our bank debt is approximately fair value based on the fact that it is subject to short-term floating interest rates that approximate the rates available to us for those periods. We adjusted the estimated fair value measurements of our bank debt at June 30, 2010, for estimated nonperformance risk of approximately $6.2 million, which was determined utilizing industry credit default swaps. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies. The fair value of the subordinated debt is based on quoted market prices. The following table presents the carrying and fair values of our debt, along with average interest rates at June 30, 2010:

	Expected Maturity Dates														Carrying		Fair
In thousands, except percentages	2012		2013		2014		2015		2016		2017		2020		Value		Value
Variable rate debt:
Denbury Credit Agreement (weighted average interest rate of 2.7% at June 30, 2010)	$	—	$	—	$	40,000	$	—	$	—	$	—	$	—	$	40,000	$	38,284
ENP Credit Agreement (weighted average interest rate of 2.7% at June 30, 2010)		245,000		—		—		—		—		—		—		245,000		240,485
Fixed rate debt:
7.5% Senior Subordinated Notes due 2013		—		225,000		—		—		—		—		—		224,466		228,094
6.25% Senior Subordinated Notes due 2014		—		—		1,072		—		—		—		—		1,084		1,072
6.0% Senior Subordinated Notes due 2015		—		—		—		484		—		—		—		490		484
7.5% Senior Subordinated Notes due 2015		—		—		—		300,000		—		—		—		300,470		303,000
9.5% Senior Subordinated Notes due 2016		—		—		—		—		224,920		—		—		240,877		238,415
9.75% Senior Subordinated Notes due 2016		—		—		—		—		426,350		—		—		402,069		460,458
7.25% Senior Subordinated Notes due 2017		—		—		—		—		—		2,250		—		2,277		2,250
8.25% Senior Subordinated Notes due 2020		—		—		—		—		—		—		996,273		996,273		1,041,105

     At this level of floating rate debt, if LIBOR increased by 10%, we would incur an additional $0.4 million of interest expense per year on revolving credit facilities, and if LIBOR decreased by 10%, we would incur $0.4 million less. Additionally, if the discount rates on our senior notes increased by 10%, we estimate the fair value of our fixed rate debt at June 30, 2010 would increase by approximately $9.9 million, and if the discount rates on our senior notes decreased by 10%, we estimate the fair value would decrease by approximately $9.9 million.

     As of June 30, 2010, the fair market value of ENP’s interest rate swaps was a net liability of approximately $3.0 million. If the Eurodollar rate increased by 10%, we estimate the liability would decrease to approximately $2.9 million, and if the Eurodollar rate decreased by 10%, we estimate the liability would increase to approximately $3.1 million.

     Please read Note 5 to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.

Commodity Derivative Contracts and Commodity Price Sensitivity

     From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars, and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. In early 2009, we began to employ a strategy to hedge a portion of our production looking out 12 to 15 months from each quarter, 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. However, as a result of the Encore Merger and the

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higher debt levels necessary to finance it, we entered into costless collars in November 2009 and March 2010, to hedge a significant portion of our forecasted production through 2011. Given the sale of the Southern Assets commencing in May 2010, we returned to our strategy initiated during early 2009 whereby we hedge a portion of our production for the next 12 to 15 months, as discussed above. Please read Notes 6 and 7 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

     All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources and are based on prices that are actively quoted. 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 revolving credit agreement and all of ENP’s commodity derivative contracts are with parties that are lenders under its revolving credit agreement. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts. We have measured nonperformance risk based upon credit default swaps or credit spreads. At June 30, 2010 and December 31, 2009, the net asset (liability) of our open commodity derivative contracts was reduced by $1.1 million and $0.8 million, respectively, for estimated nonperformance risk.

     For accounting purposes, we do not apply hedge accounting to our commodity derivative contracts. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.

     At June 30, 2010, our commodity derivative contracts were recorded at their fair value, which was a net asset of approximately $109.7 million (excluding $38.1 million of deferred premiums that Denbury is obligated to pay for its derivative contracts, which payments are not subject to changes in commodity prices), a significant change from the $128.7 million fair value liability recorded at December 31, 2009. This change is primarily related to the expiration of oil derivative contracts during the first quarter of 2010 and to the oil and natural gas futures prices as of June 30, 2010 in relation to the new commodity derivative contracts for 2010 and 2011 that we entered into during the first quarter of 2010.

     Based on NYMEX crude oil and natural gas futures prices as of June 30, 2010, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil and natural gas derivative contracts as seen in the following table:

	Crude Oil			Natural Gas
	Derivative			Derivative
	Contracts			Contracts
	Receipt /
In thousands	(Payment)			Receipt
Based on:
NYMEX futures prices as of June 30, 2010	$	(14,570	)	$	54,856
10% increase in prices		(43,384	)		31,432
10% decrease in prices		31,137			78,459

Item 4. Controls and Procedures

     Evaluation of Disclosure Controls and Procedures.We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, consisting of internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer. Our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow

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timely decisions regarding required disclosure.

     Evaluation of Changes in Internal Control Over Financial Reporting.There have been no changes in our internal control over financial reporting during the most recently completed quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     Information with respect to this item is incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2009, updated as follows. On June 11, 2010, Judge Womack, the Presiding Judge in the Israni and Scott class action cases related to the Encore Merger and pending in Tarrant County District Court, granted the defendants’ motions striking the merger class action claims of the Harbor Police Retirement System and Harbor Police efforts to intervene in the Israni and Scott cases. On August 5, 2010, Judge Womack preliminarily approved the Stipulation of Settlement dated June 22, 2010, settling the Israni and Scott cases, permitting Encore shareholders the right to opt-out of the settlement, appointing representatives of the class and their counsel, approving the notice of class action which must be mailed to former Encore shareholders by August 26, 2010, and setting a hearing on October 21, 2010 to consider final approval of the settlement, certification of the class and dismissal of the case with prejudice. The settlement amount agreed upon with the Israni and Scott plaintiffs is immaterial to us.

Item 1A. Risk Factors

     Information with respect to the risk factors has been incorporated by reference from Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to the risk factors since the filing of such Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

     The following table summarizes purchases of our common stock during the second quarter of 2010:

					Total Number of		Approximate Dollar
	Total				Shares Purchased		Value of Shares
	Number of		Average		as Part of Publicly		that May Yet Be
	Shares		Price Paid		Announced Plans or		Purchased Under the
Month	Purchased		per Share		Programs		Plans or Programs
April 2010		25,328	$	17.99		—		—
May 2010		18,959		16.47		—		—
June 2010		18,993		15.33		—		—
Total		63,280		16.74		—	$	—

     These shares were purchased from our employees who delivered shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares.

Item 6. Exhibits

Exhibit	Description
10.1	First Amendment to Credit Agreement, dated as of May 13, 2010, among Denbury Resources Inc., as Borrower, the financial institutions listed on Schedule 1.1 thereto, as Banks, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, and BNP Paribas, The Bank of Nova Scotia, and Credit Suisse Securities (USA) LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed with the SEC on May 19, 2010).
10.2	Purchase and Sale Agreement, dated March 31, 2010, effective May 1, 2010, by and between Encore Operating, L.P. and Quantum Resources Management, LLC (incorporated by reference to Exhibit 10.6 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, filed with the SEC on May 10, 2010).
10.3+	2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (Updated as of May 19, 2010) (incorporated by reference to Exhibit 99.1 of our Current Report on Form 8-K, filed with the SEC on May 25, 2010).
10.4+	Form of 2010 Performance Stock Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (Updated as of May 19, 2010) (incorporated by reference to Exhibit 99.2

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Exhibit	Description
	of our Current Report on Form 8-K, filed with the SEC on May 25, 2010).
10.5+	Form of 2010 Performance Cash Award under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (Updated as of May 19, 2010) (incorporated by reference to Exhibit 99.3 of our Current Report on Form 8-K, filed with the SEC on May 25, 2010).
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following financial statements from our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, formatted in XBRL: (1) Unaudited Condensed Consolidated Balance Sheets, (2) Unaudited Condensed Consolidated Statements of Operations, (3) Unaudited Condensed Consolidated Statements of Cash Flows, (4) Unaudited Condensed Consolidated Statement of Changes in Equity, and (5) Unaudited Condensed Consolidated Statements of Comprehensive Operations.

*	Filed herewith.
+	Compensatory arrangement.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DENBURY RESOURCES INC.
By:	/s/ Mark C. Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary
By:	/s/ Alan Rhoades
	Alan Rhoades
	Vice President, Accounting

Date: August 9, 2010

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