10-Q

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, 2013

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 jurisdictionof incorporation or organization)	(I.R.S. EmployerIdentification No.)
5320 Legacy Drive, Plano, TX	75024
(Address of principal executive offices)	(Zip Code)

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

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

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

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

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at July 31, 2013
Common Stock, $.001 par value	372,912,110

Denbury Resources Inc.

Table of Contents

		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2013 and December 31, 2012	3
	Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	4
	Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 30, 2013 and 2012	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33
Item 4.	Controls and Procedures	35
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Mine Safety Disclosures	36
Item 5.	Other Information	37
Item 6.	Exhibits	37
	Signatures	38
	Exhibit 10(c)
	Exhibit 10(d)
	Exhibit 10(e)
	Exhibit 31(a)
	Exhibit 31(b)
	Exhibit 32

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Resources Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

	June 30, 2013			December 31, 2012
Assets
Current assets
Cash and cash equivalents	$	75,865		$	98,511
Restricted cash	—			1,050,015
Accrued production receivable	256,572			253,131
Trade and other receivables, net	94,814			81,971
Derivative assets	9,915			19,477
Deferred tax assets	30,392			29,156
Other current assets	16,500			10,493
Total current assets	484,058			1,542,754
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved	8,144,381			6,963,211
Unevaluated	1,126,585			809,154
CO2 properties	1,068,890			1,032,653
Pipelines and plants	2,115,243			2,035,126
Other property and equipment	424,919			417,207
Less accumulated depletion, depreciation, amortization, and impairment	(3,406,131		)	(3,180,241		)
Net property and equipment	9,473,887			8,077,110
Derivative assets	18,712			36
Goodwill	1,283,590			1,283,590
Other assets	248,263			235,852
Total assets	$	11,508,510		$	11,139,342
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities	$	395,652		$	414,668
Oil and gas production payable	182,657			161,945
Derivative liabilities	1,895			2,842
Current maturities of long-term debt	34,148			36,966
Total current liabilities	614,352			616,421
Long-term liabilities
Long-term debt, net of current portion	3,198,911			3,104,462
Asset retirement obligations	115,049			102,730
Derivative liabilities	87			23,781
Deferred tax liabilities	2,283,028			2,153,452
Other liabilities	26,297			23,607
Total long-term liabilities	5,623,372			5,408,032
Commitments and contingencies (Note 7)
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	—			—
Common stock, $.001 par value, 600,000,000 shares authorized; 408,547,073 and 406,163,194 shares issued, respectively	409			406
Paid-in capital in excess of par	3,161,193			3,136,461
Retained earnings	2,652,386			2,434,835
Accumulated other comprehensive loss	(311		)	(348		)
Treasury stock, at cost, 35,642,949 and 30,601,262 shares, respectively	(542,891		)	(456,465		)
Total stockholders' equity	5,270,786			5,114,889
Total liabilities and stockholders' equity	$	11,508,510		$	11,139,342

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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues and other income
Oil, natural gas, and related product sales	$	638,188		$	592,141		$	1,211,841		$	1,225,642
CO2 sales and transportation fees	6,562			5,301			13,120			12,096
Interest income and other income	5,334			4,339			8,209			9,159
Total revenues and other income	650,084			601,781			1,233,170			1,246,897
Expenses
Lease operating expenses	220,558			124,511			361,100			262,475
Marketing expenses	13,332			12,218			23,128			23,048
CO2 discovery and operating expenses	3,419			1,062			7,141			7,267
Taxes other than income	44,940			38,812			82,951			82,506
General and administrative expenses	33,382			34,826			75,271			71,433
Interest, net of amounts capitalized of $23,279, $18,475, $44,984, and $37,920, respectively	30,602			41,604			66,636			77,918
Depletion, depreciation, and amortization	126,907			132,289			239,805			253,184
Derivatives expense (income)	(45,501		)	(139,109		)	(33,572		)	(93,834		)
Loss on early extinguishment of debt	428			—			44,651			—
Impairment of assets	—			215			—			17,515
Other expenses	10,711			12,552			12,818			23,272
Total expenses	438,778			258,980			879,929			724,784
Income before income taxes	211,306			342,801			353,241			522,113
Income tax provision	81,326			130,936			135,690			196,781
Net income	$	129,980		$	211,865		$	217,551		$	325,332
Net income per common share – basic	$	0.35		$	0.55		$	0.59		$	0.84
Net income per common share – diluted	$	0.35		$	0.54		$	0.58		$	0.83
Weighted average common shares outstanding
Basic	368,850			387,159			369,122			386,764
Diluted	371,969			390,702			372,417			390,823

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Net income	$	129,980	$	211,865	$	217,551	$	325,332
Other comprehensive income, net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $10, $19, and $21, respectively	17		17		37		35
Total other comprehensive income	17		17		37		35
Comprehensive income	$	129,997	$	211,882	$	217,588	$	325,367

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,
	2013			2012
Cash flow from operating activities:
Net income	$	217,551		$	325,332
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation, and amortization	239,805			253,184
Deferred income taxes	128,342			167,289
Stock-based compensation	15,671			15,249
Noncash fair value derivative adjustments	(33,516		)	(87,686		)
Loss on early extinguishment of debt	44,651			—
Amortization of debt issuance costs and discounts	7,139			7,347
Impairment of assets	—			17,515
Other, net	5,041			15,835
Changes in assets and liabilities, net of effects from acquisitions:
Accrued production receivable	(6,769		)	35,466
Trade and other receivables	3,117			(10,769		)
Other current and long-term assets	(9,171		)	6,851
Accounts payable and accrued liabilities	86,969			28,256
Oil and natural gas production payable	20,222			(7,985		)
Other liabilities	(12,308		)	(33,264		)
Net cash provided by operating activities	706,744			732,620
Cash flow used in investing activities:
Oil and natural gas capital expenditures	(486,163		)	(574,008		)
Acquisitions of oil and natural gas properties	(307		)	(154,366		)
CO2 capital expenditures	(44,708		)	(53,313		)
Pipelines and plants capital expenditures	(97,480		)	(169,675		)
Purchases of other assets	(22,825		)	(10,748		)
Net proceeds from sales of oil and natural gas properties and equipment	5,496			32,302
Proceeds from sale of short-term investments	—			83,545
Other	(19,586		)	(2,961		)
Net cash used in investing activities	(665,573		)	(849,224		)
Cash flow provided by (used in) financing activities:
Bank repayments	(970,000		)	(400,000		)
Bank borrowings	530,000			535,000
Repayment of senior subordinated notes	(651,270		)	—
Premium paid on repayment of senior subordinated notes	(36,475		)	—
Proceeds from issuance of senior subordinated notes	1,200,000			—
Costs of debt financing	(20,026		)	(11		)
Common stock repurchase program	(100,423		)	—
Other	(15,623		)	(8,965		)
Net cash provided by (used in) financing activities	(63,817		)	126,024
Net increase (decrease) in cash and cash equivalents	(22,646		)	9,420
Cash and cash equivalents at beginning of period	98,511			18,693
Cash and cash equivalents at end of period	$	75,865		$	28,113

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2012 (the "Form 10-K").  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of June 30, 2013, our consolidated results of operations for the three and six months endedJune 30, 2013 and 2012, and our consolidated cash flows for the six months ended June 30, 2013 and 2012.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.

Net Income per Common Share

Basic net income per common share is computed by dividing net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance-based equity awards.  For the three and six months endedJune 30, 2013 and 2012, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.

The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:

	Three Months Ended June 30,		Six Months Ended June 30,
In thousands	2013	2012	2013	2012
Basic weighted average common shares outstanding	368,850	387,159	369,122	386,764
Potentially dilutive securities:
Restricted stock, stock options, SARs and performance-based equity awards	3,119	3,543	3,295	4,059
Diluted weighted average common shares outstanding	371,969	390,702	372,417	390,823

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Basic weighted average common shares excludes shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. Stock options and SARs of 3.7 million shares for the three and six months ended June 30, 2013, respectively, and 3.9 million and 3.5 million shares for the three and six months ended June 30, 2012, respectively, were not included in the computation of diluted net income per share as their effect would have been antidilutive.

Recent Accounting Pronouncements

Balance Sheet Offsetting. In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the Financial Accounting Standards Board Codification ("FASC"), including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 became effective for our fiscal year beginning January 1, 2013 and have been applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 did not affect our consolidated financial statements, but required additional disclosures in the notes thereto.

Note 2. Acquisitions and Divestitures

Fair Value. 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 do not impact the measurement of fair value unless those assumptions are consistent with market participant views.

The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions may include: (1) NYMEX oil and natural gas futures (this input is observable); (2) dollar-per-acre values of recent sale transactions (this input is observable); (3) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible; (4) estimated oil and natural gas pricing differentials; (5) projections of future rates of production; (6) timing and amount of future development and operating costs; (7) projected costs of CO₂ (to a market participant); (8) projected reserve recovery factors; and (9) risk-adjusted discount rates.

2013 Acquisition

Cedar Creek Anticline Acquisition. In January 2013, we entered into an agreement to acquire producing assets in the Cedar Creek Anticline ("CCA") of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips Company ("ConocoPhillips") for $1.05 billion. On March 27, 2013, we closed the acquisition for $989.0 million in cash after closing adjustments, primarily for revenues and costs of the purchased properties from the January 1, 2013 effective date to the closing date. We funded the acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction (described below) from which $1.05 billion was placed in qualifying trust accounts in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. The $1.05 billion placed in qualifying trust accounts was classified as Restricted Cash in our December 31, 2012 Consolidated Balance Sheet. This acquisition meets the definition of a business under the FASC Business Combinations topic. As such, we estimated the fair value of assets acquired and liabilities assumed as of March 27, 2013, the closing date of the acquisition, using a discounted future net cash flow model. The current purchase price allocation is preliminary, pending further evaluation of the oil and natural gas properties, other assets and related asset retirement obligations.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed in the CCA acquisition:

In thousands
Consideration:
Cash payment (1)	$	988,982
Fair value of assets acquired and liabilities assumed:
Oil and natural gas properties
Proved	771,487
Unevaluated	222,820
Other assets	1,884
Asset retirement obligations	(7,209		)
	$	988,982

(1) This cash payment was made through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

For the three months ended June 30, 2013 and for the period from March 27, 2013 to June 30, 2013, we recognized $88.7 million and $92.7 million of oil, natural gas, and related product sales, respectively, from the property interests acquired in the CCA acquisition. For the three months ended June 30, 2013 and for the period from March 27, 2013 to June 30, 2013, we recognized $65.2 million and $67.9 million of net field operating income (oil, natural gas and related product sales less lease operating expenses and production and ad valorem taxes and marketing expenses), respectively, related to the CCA acquisition.

2012 Acquisitions and Divestitures

Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction (the "Bakken Exchange Transaction") with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”) in which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash (after closing adjustments), (2) ExxonMobil's operating interests in Webster Field in Texas and Hartzog Draw Field in Wyoming, and (3) approximately a one-third overriding royalty ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field in Wyoming. No material adjustments were made during the first six months of 2013 to the preliminary fair value of the assets acquired and liabilities assumed previously disclosed in our Form 10-K.

Thompson Field Acquisition. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after closing adjustments. The field is located in close proximity to Hastings Field, which is an enhanced oil recovery field that we are currently flooding with CO₂ and which is the current terminus of the Green Pipeline which transports CO₂ both from the Jackson Dome area, located near Jackson, Mississippi, and from various anthropogenic sources. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also a planned future tertiary field. Under the terms of the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO₂ injection.

This acquisition meets the definition of a business under the FASC Business Combinations topic. The fair values assigned to assets acquired and liabilities assumed in the June 2012 acquisition have been finalized and no adjustments have been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2012.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Unaudited Pro Forma Acquisition Information. The following combined pro forma total revenues and other income and net income are presented as if the CCA Acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per share data	2013		2012		2013		2012
Pro forma total revenues and other income	$	650,084	$	640,996	$	1,315,344	$	1,327,045
Pro forma net income	129,980		234,621		245,571		368,152
Pro forma net income per common share
Basic	$	0.35	$	0.61	$	0.67	$	0.95
Diluted	0.35		0.60		0.66		0.94

Other 2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million. The sale had an effective date of January 1, 2012 and proceeds received after consideration of final closing adjustments totaled $68.5 million. In February 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for net proceeds of $141.8 million, after final closing adjustments. The sale had an effective date of December 1, 2011. We did not record a gain or loss on these divestitures in accordance with the full cost method of accounting.

Note 3. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:

	June 30,			December 31,
In thousands	2013			2012
Bank Credit Agreement	$	260,000		$	700,000
9½% Senior Subordinated Notes due 2016, including premium of $9,118	—			234,038
9¾% Senior Subordinated Notes due 2016, including discount of $13,569	—			412,781
8¼% Senior Subordinated Notes due 2020	996,273			996,273
6 3/8% Senior Subordinated Notes due 2021	400,000			400,000
4 5/8% Senior Subordinated Notes due 2023	1,200,000			—
Other Subordinated Notes, including premium of $21 and $25, respectively	3,828			3,832
Pipeline financings	231,626			236,244
Capital lease obligations	141,332			158,260
Total	3,233,059			3,141,428
Less: current obligations	(34,148		)	(36,966		)
Long-term debt and capital lease obligations	$	3,198,911		$	3,104,462

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

4 5/8% Senior Subordinated Notes due 2023

In February 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the “2023 Notes”). The 2023 Notes, which carry a coupon rate of 4.625%, were sold at par. The net proceeds, after issuance costs, of approximately $1.18 billion were used to repurchase or redeem a portion of our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes"), all of our 9¾% Senior

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Subordinated Notes due 2016 (the "9¾% Notes") (see Repurchase and Redemption of 9½% Notes and 9¾% Notes below) and to pay down a portion of outstanding borrowings on our Bank Credit Facility (as defined below).

The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year, commencing July 15, 2013. We may redeem the 2023 Notes in whole or in part at our option beginning January 15, 2018, at the following redemption prices: 102.313%on or after January 15, 2018; 101.542%on or after January 15, 2019; 100.771%on or after January 15, 2020; and 100%on or after January 15, 2021. Prior to January 15, 2016, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2023 Notes at a redemption price of 104.625% with the proceeds of certain equity offerings. In addition, at any time prior to January 15, 2018, we may redeem 100% of the principal amount of the 2023 Notes at a redemption price equal to 100% of the principal amount plus a “make whole” premium and accrued and unpaid interest. The indenture for the 2023 Notes (the "2023 Indenture") contains certain restrictions on our ability to take or permit certain actions, including restrictions on our ability to: (1) incur additional debt; (2) pay dividends on our common stock or redeem, repurchase or retire such stock or subordinated debt unless certain leverage ratios are met; (3) make investments; (4) create liens on our assets; (5) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (6) engage in transactions with our affiliates; (7) transfer or sell assets; and (8) consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. Although the covenants contained in our other senior subordinated notes indentures are generally consistent with those contained in our 2023 Indenture, the 2023 Indenture covenants permit us in certain circumstances to make restricted payments exceeding the amount allowed under our other senior subordinated notes indentures.  Under the 2023 Indenture, these restricted payments, which include share repurchases and dividend payments, do not reduce our restricted payment limitation, provided we maintain (both before and after giving effect to any such payment) a predefined leverage ratio of at least 2.5 to 1. The leverage ratio represents the ratio of total debt to EBITDA, both as defined within the 2023 Indenture.

Repurchase and Redemption of 9½% Notes and 9¾% Notes

On January 22, 2013, we commenced cash tender offers to purchase the outstanding $426.4 million principal amount of our 9¾% Notes at 105.425% of par and the outstanding $224.9 million principal amount of our 9½% Notes at 106.869% of par. During February 2013, we accepted for purchase $191.7 million principal amount of the outstanding 9¾% Notes and $186.7 million principal amount of the outstanding 9½% Notes. We received sufficient consents in the solicitation to amend the indenture governing the 9½% Notes to eliminate most of the restrictive covenants and certain events of default. The purchases under these tender offers were funded by a portion of the proceeds received from the issuance of our 2023 Notes. The tender offers expired on February 19, 2013.

On February 5, 2013, we issued a notice of redemption for the remaining $234.7 million principal amount outstanding of our 9¾% Notes at 104.875% of par, and on March 7, 2013, we repurchased all of the remaining 9¾% Notes outstanding. On March 28, 2013, we issued a notice of redemption for the remaining $38.2 million principal amount outstanding of our 9½% Notes at 104.75% of par, and on May 1, 2013, we repurchased all of the remaining 9½% Notes outstanding.

We recognized a loss associated with the debt repurchases of $0.4 million and $44.7 million during the three and six months endedJune 30, 2013, respectively, consisting of both premium payments made to repurchase or redeem the 9¾% Notes and 9½% Notes and the elimination of unamortized debt issuance costs, discounts and premiums related to these notes. The loss is included in our Unaudited Condensed Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt".

$1.6 Billion Revolving Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the "Bank Credit Agreement").  Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations.  The borrowing base is adjusted at the banks' discretion and is based in part upon external factors over which we have no control.  If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period not to exceed four months. As part of the semi-annual review completed on May 1, 2013 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion. Our next semi-annual redetermination is scheduled to occur on or around November 1, 2013.  The weighted average interest rate on borrowings under this revolving credit facility, evidenced by the Bank Credit Agreement (the "Bank Credit Facility") was 1.7%

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

as of June 30, 2013.  We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base.  Loans under the Bank Credit Facility mature in May 2016.

Note 4. Share Repurchase Program

Under our board-authorized share repurchase program, we repurchased 1.1 million shares of Denbury common stock for $19.0 million during the three months ended June 30, 2013 and 5.0 million shares of Denbury common stock for $85.2 million during the six months ended June 30, 2013. Since commencement of the share repurchase program in October 2011 through June 30, 2013, we have repurchased a total of 36.1 million shares of Denbury common stock for $547.1 million, or $15.15 per share. As of June 30, 2013, we had $224.1 million of remaining repurchases authorized under our share repurchase program.

Note 5. Derivative Instruments

Oil and Natural Gas Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production approximately two years in the future from the current 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 and commodity price volatility. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands	2013			2012			2013			2012
Oil
Cash payment on settlements of derivative contracts	$	—		$	709		$	—		$	8,939
Noncash fair value adjustments to derivative contracts – income	(45,501		)	(140,923		)	(33,572		)	(98,478		)
Total derivatives income – oil	(45,501		)	(140,214		)	(33,572		)	(89,539		)
Natural Gas
Cash receipt on settlements of derivative contracts	—			(7,991		)	—			(15,031		)
Noncash fair value adjustments to derivative contracts – expense	—			9,096			—			10,736
Total derivatives expense (income) – natural gas	—			1,105			—			(4,295		)
Derivatives expense (income)	$	(45,501	)	$	(139,109	)	$	(33,572	)	$	(93,834	)

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Commodity Derivative Contracts Not Classified as Hedging Instruments

The following table presents outstanding oil derivative contracts with respect to future production as of June 30, 2013:

					Contract Prices per Barrel of Oil
		Type of	Pricing	Volume					Weighted Average Price
Year	Months	Contract	Index	(Barrels per day)	Range				Floor		Ceiling
2013	July – Sept	Collar	NYMEX	56,000	$	75.00	–	133.10	$	79.64	$	109.15
	Oct – Dec	Collar	NYMEX	54,000		80.00	–	127.50	80.00		117.53
2014	Jan – Mar	Collar	NYMEX	58,000	$	80.00	–	104.50	$	80.00	$	102.11
	Apr – June	Collar	NYMEX	58,000		80.00	–	104.50	80.00		102.11
	July – Sept	Collar	NYMEX	58,000		80.00	–	100.00	80.00		97.73
	Oct – Dec	Collar	NYMEX	58,000		80.00	–	100.00	80.00		97.73
2015	Jan – Mar	Collar	NYMEX	38,000	$	80.00	–	100.90	$	80.00	$	96.96
	Jan – Mar	Collar	LLS	20,000		85.00	–	104.00	85.00		101.45
	Apr – June	Collar	NYMEX	24,000		80.00	–	95.25	80.00		94.40
	Apr – June	Collar	LLS	20,000		85.00	–	103.00	85.00		102.01

Additional Disclosures about Derivative Instruments

At June 30, 2013 and December 31, 2012, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

		Estimated Fair Value Asset (Liability)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2013			2012
		In thousands
Derivative assets
Crude oil contracts	Derivative assets – current	$	9,915		$	19,477
Crude oil contracts	Derivative assets – long-term	18,712			36
Derivative liabilities
Crude oil contracts	Derivative liabilities – current	(1,895		)	(2,659		)
Deferred premiums	Derivative liabilities – current	—			(183		)
Crude oil contracts	Derivative liabilities – long-term	(87		)	(23,781		)
Total derivatives not designated as hedging instruments		$	26,645		$	(7,110	)

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, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement. As of June 30, 2013 all of our outstanding derivative contracts were subject to enforceable master netting

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

Note 6. Fair Value Measurements

The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

• Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. We currently have 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. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

• Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2013, instruments in this category include non-exchange-traded oil collars that are based on regional pricing other than NYMEX (i.e., Louisiana Light Sweet). Our costless collars are valued using the Black-Scholes model, which is described above. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. A one percent increase or decrease in implied volatility would result in a change of approximately $0.3 million in the fair value of these instruments as of June 30, 2013.

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:

	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
June 30, 2013
Assets:
Oil derivative contracts	$	—	$	25,444		$	3,183		$	28,627
Liabilities:
Oil derivative contracts	—		(1,895		)	(87		)	(1,982		)
Total	$	—	$	23,549		$	3,096		$	26,645
December 31, 2012
Assets:
Oil derivative contracts	$	—	$	19,513		$	—		$	19,513
Liabilities:
Oil derivative contracts	—		(26,440		)	—			(26,440		)
Total	$	—	$	(6,927	)	$	—		$	(6,927	)

Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

During the first quarter of 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of Faustina Hydrogen Products LLC, which impairment was classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statement of Operations for the six months ended June 30, 2012.  The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset.  These inputs are unobservable within the marketplace and therefore considered Level 3 within the fair value hierarchy.  However, as there are currently no expected future cash flows associated with the plant, the preferred stock was determined to have no value.

Other Fair Value Measurements

The carrying value of our Bank Credit Facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine fair value of our fixed-rate debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our total long-term debt as of June 30, 2013 and December 31, 2012, excluding pipeline financing and capital lease obligations, was $2.855 billion and $2.957 billion, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 7. Commitments and Contingencies

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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.  We are also subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe.

Delhi Field Release

In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and a small percentage of oil, was discovered and reported within the Denbury-operated Delhi Field located in northern Louisiana.  Denbury immediately took remedial action to stop the release and contain and recover well fluids in the affected area. We continue to actively work with government and local officials and agencies to determine the best course of remediation. Currently, we believe the origin of the release to be one or more wells in the affected area of the field that had been previously plugged and abandoned. We currently estimate that we will incur a minimum of $70.0 million to stop the release and remediate the affected area. Accordingly, during the second quarter of 2013, we recorded $70.0 million of lease operating expense related to the release in our Unaudited Condensed Consolidated Statement of Operations and a corresponding liability classified as Accounts payable and accrued liabilities in our Unaudited Condensed Consolidated Balance Sheet. This estimate is based on costs incurred through July 31, 2013 of approximately $45.0 million, plus the Company's estimate of the minimum level of future costs based on our current understanding of the environmental impact of the release and methods available to remediate impacted properties. Since the area is still in the process of being remediated and final restoration plans have not yet been agreed upon with regulatory agencies, we are currently unable to reliably estimate the full extent of the costs that may ultimately be incurred by the Company related to this release. The Company maintains insurance coverage which we believe covers certain of the costs and damages related to the release, and we currently estimate that one-third to two-thirds of our minimum cost estimate may be recoverable under our insurance policies. However, we have not reached any agreement with our insurance carriers as to recoverable amounts, and given the uncertainties concerning our ultimate insurance recoveries, we have not recognized any such recoveries in our financial statements as of June 30, 2013. Insurance recoveries will be recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.

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Denbury Resources Inc.

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.  Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

Our primary focus is on enhanced oil recovery utilizing CO₂, and our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. We are the largest combined oil and natural gas producer in both Mississippi and Montana, and we own the largest reserves of CO₂ used for tertiary oil recovery east of the Mississippi River. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary recovery operations.

Operating Highlights. The second quarter of 2013 was the first quarter that reflects the full operational impact of all of the assets we acquired as part of, or with the proceeds of, the Bakken area asset sale, which closed during the fourth quarter of 2012. These acquired assets include additional interests in the Cedar Creek Anticline ("CCA"), which we purchased late in the first quarter of 2013 (See Note 2, Acquisitions and Divestitures, to the Unaudited Condensed Consolidated Financial Statements for additional details surrounding the Bakken exchange transaction).

During the second quarter of 2013, we recognized net income of $130.0 million, or $0.35 per diluted common share, compared to net income of $211.9 million, or $0.54 per diluted common share, during the second quarter of 2012.  Despite a $46.0 millionincrease in oil and natural gas revenues between the two periods, net income declined between the two periods primarily due to a decline of $86.3 million in pre-tax income related to the fair value change in our commodity derivative contracts between the two periods and a $96.0 million increase in lease operating expense in the most recent quarter, $70.0 million of which represents our estimate of the minimum costs to remediate the impacted area of Delhi Field subsequent to a release of well fluids in mid-June 2013. See Results of Operations – Operating Results Summary – Oil and Natural Gas Derivative Contracts and Delhi Field Release below for more information.

During the second quarter of 2013, our oil and natural gas production, which was 94% oil, increased 2%, from an average of 72,337 BOE/d produced during the second quarter of 2012 to an average of 74,052 BOE/d produced during the second quarter of 2013.  The increase was due to an increase in tertiary production, together with the acquisition of additional interests in CCA and other non-tertiary production growth, primarily offset by the decline in production resulting from the divestiture of our Bakken area assets late in 2012.  Our tertiary oil production averaged 38,752 Bbls/d during the second quarter of 2013, an increase of 10% over the 35,208 Bbls/d produced during the second quarter of 2012, but down slightly from our average tertiary production of 39,057 Bbls/d in the first quarter of 2013.  See Results of Operations – Operating Results Summary – Production for more information.

Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, increased3% to $98.92 per Bbl during the second quarter of 2013, compared to $95.63 per Bbl during the second quarter of 2012, but down from the $105.59 per Bbl average realized price in the first quarter of 2013.  The actual oil price we realized relative to NYMEX oil prices (our NYMEX oil price differential) improved to $4.78 per Bbl above NYMEX prices in the second quarter of 2013, compared to a positive $2.14 per Bbl NYMEX differential in the second quarter of 2012, but was down from the $11.17 NYMEX differential in the first quarter of 2013.  The improved oil price differential realized this quarter compared to the prior year is primarily due to the disposition of our Bakken area assets late in 2012, which production generally sold at a significant discount to NYMEX. See Results of Operations – Operating Results Summary – Oil and Natural Gas Revenues below for more information on our oil prices received and differentials to NYMEX prices.

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Denbury Resources Inc.

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

Cedar Creek Anticline Acquisition. On March 27, 2013, we closed our acquisition of producing assets in the CCA of Montana and North Dakota in a purchase from a wholly-owned subsidiary of ConocoPhillips Company ("ConocoPhillips") for $989.0 million in cash, after preliminary standard closing adjustments, primarily for revenues and costs of the properties purchased from the January 1, 2013 effective date to the closing date. We funded the acquisition with a portion of the cash proceeds from the Bakken exchange transaction, $1.05 billion of which was placed in qualifying trust accounts in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. The assets purchased include both additional interests in certain of our existing operated fields in CCA, as well as operating interests in other CCA fields. In conjunction with this acquisition, we added 42.2 MMBOE of estimated proved reserves.

Rocky Mountain Tertiary Operations Startup. In late 2012, we completed construction of the first section of the 20-inch Greencore Pipeline in Wyoming, our first CO₂ pipeline in the Rocky Mountain region, and received the first CO₂ deliveries from the Lost Cabin gas plant in central Wyoming during the first quarter of 2013. We started injections at our Bell Creek Field in Montana during the second quarter of 2013, and our first tertiary oil production from this field commenced in July 2013. In December 2012, we completed the required three-mile CO₂ pipeline to deliver CO₂ from our source at LaBarge Field to Grieve Field in Wyoming and began injecting CO₂ into Grieve Field during the first quarter of 2013. We currently do not expect any tertiary production from Grieve Field until 2015.

Debt Refinancing. In February 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the "2023 Notes"). The net proceeds of approximately $1.18 billion were used to repurchase or redeem our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes"), our 9¾% Senior Subordinated Notes due 2016 (the "9¾% Notes") and to pay down a portion of outstanding borrowings on our bank credit facility. During the three and six months endedJune 30, 2013, we recognized a loss associated with the debt repurchases of $0.4 million and $44.7 million, respectively, which is included in our Unaudited Condensed Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt". See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for additional details surrounding the repurchase and redemption of our 9½% Notes and 9¾% Notes.

Addition of Proved CO₂ Reserves. During the first six months of 2013, we added approximately 350 Bcf of estimated proved CO₂ reserves as a result of successful drilling in the Jackson Dome area, our primary source of CO₂ for the Gulf Coast region.

Evaluation of Means of Distributing Future Free Cash Flow to Stockholders. The Company is engaged in an internal analysis of its options for distributing the significant future levels of free cash flow we currently anticipate generating in 2017 and beyond to stockholders, along with whether and how we could accelerate any such cash distributions. In general, this analysis includes evaluation of different organizational structures, and the timing of development of future capital projects. The Company is targeting completion of this analysis and any accompanying decisions by its November 11, 2013 analyst meeting, and does not anticipate making any further announcement regarding this process prior to that time.

Delhi Field Release. In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and a small percentage of oil, was discovered and reported within the Denbury-operated Delhi Field located in northern Louisiana.  Denbury immediately took remedial action to stop the release and contain and recover well fluids in the affected area. We continue to actively work with government and local officials and agencies to determine the best course of remediation. Currently, we believe the origin of the release to be one or more wells in the affected area of the field that had been previously plugged and abandoned. During the second quarter of 2013, we recorded $70.0 million of lease operating expense related to the release, which amount represents our current estimate of the minimum amount we expect to incur as a result of the release. Our estimate of these costs is preliminary and is based on a number of contingencies which have not been resolved, and the costs of which are not currently quantifiable. The Company maintains insurance coverage which we believe covers certain of the costs and damages related to the release, and we currently estimate that one-third to two-thirds of our minimum cost estimate may be recoverable under our insurance policies. However, we have not reached any agreement with our insurance carriers as to recoverable amounts, and given the uncertainties concerning our ultimate insurance recoveries, we have not recognized any such recoveries in our financial statements as of June 30, 2013. See Note 7, Commitments and Contingencies to the Unaudited Condensed Consolidated Financial Statements for further discussion.

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Denbury Resources Inc.

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

CAPITAL RESOURCES AND LIQUIDITY

2013 Capital Spending. We currently expect that our 2013 capital budget will be $1.06 billion, excluding acquisitions. In addition, we currently estimate spending approximately $160 million in capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.  Our current 2013 capital budget is comprised of the following:

• $580 million allocated for tertiary oil field expenditures;

• $110 million for pipeline construction;

• $200 million to be spent on CO₂ sources;

• $170 million to be spent in all other areas; and

• $160 million for other capital items such as capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods.

During the six months ended June 30,2013, we incurred capital expenditures of approximately $540.9 million, exclusive of property acquisitions and capitalized interest.  See additional detail on our expenditures in the Capital Expenditure Summary below.

Based on oil and natural gas commodity futures prices in early August 2013 and our current production forecast, at this time we anticipate that our 2013 cash flow from operations should be more than adequate to cover our 2013 capital budget. If prices were to decrease or changes in operating results were to cause us to have a significant reduction in anticipated 2013 cash flows, we have ample availability on our bank credit facility to cover any potential shortfall, and we also have the ability to reduce our capital expenditures if desired. In addition, we have oil derivative contracts in place with an $80 NYMEX floor price for a significant portion of our anticipated oil production for 2013 through mid-2015 to provide an economic hedge of our exposure to commodity prices. See Note 5, Derivative Instruments to the Unaudited Condensed Consolidated Financial Statements for details of our oil commodity contacts.

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 2013 and some future years, we have contracted for certain capital expenditures; therefore, we cannot eliminate all of our capital commitments without penalties (refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations in the Form 10-K).

Bank Credit Facility. Our primary source of capital is our cash flow from operations. We use our bank credit facility as needed for acquisitions and to bridge the relatively minor timing differences between our cash flow and capital expenditure program. As part of our semiannual bank review, in early May 2013 the borrowing base for our bank credit facility was reaffirmed at $1.6 billion. Our next borrowing base redetermination is scheduled on or around November 1, 2013. We currently do not anticipate any reduction in our borrowing base as part of that redetermination, and we believe, based on current commodity prices and our proved asset base, that we could obtain lender approval to significantly increase the borrowing base under our bank credit facility above the current $1.6 billion level if we desired to do so. As of June 30, 2013, we had $1.3 billion of unused availability under our bank credit facility and cash of $75.9 million, leaving us significant liquidity to fund any cash shortfall for capital expenditures.

Share Repurchase Program. Our Board of Directors has approved a common share repurchase program for up to $771.2 million of our common shares, under which we have purchased a total of 36.1 million shares of Denbury common stock for $547.1 million, or an average of $15.15 per share, between commencement of the share repurchase program in October 2011 and June 30, 2013. As of June 30, 2013, we have $224.1 million remaining under our authorized share repurchase program. See Note 4, Share Repurchase Program to the Unaudited Condensed Consolidated Financial Statements for further discussion. Our share repurchases will be determined based on various parameters; therefore, our share repurchases may be less than the remaining approved balance under the program and there is no set expiration date for our program. We anticipate that additional repurchases during 2013 will be primarily funded with excess cash flow from operations or with borrowings under our bank credit facility.

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Denbury Resources Inc.

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

Capital Expenditure Summary. The following table of capital expenditures includes accrued capital for the six months ended June 30,2013 and 2012:

	Six Months Ended
	June 30,
In thousands	2013		2012
Capital expenditures by project:
Tertiary oil fields	$	319,698	$	246,633
CO2 pipelines	20,767		83,115
CO2 sources (1)	75,497		132,096
Other areas	124,931		305,535
Capital expenditures before acquisitions and capitalized interest	540,893		767,379
Less: recoveries from sale/leaseback transactions	—		(33,131		)
Net capital expenditures excluding acquisitions and capitalized interest	540,893		734,248
Property acquisitions (2)	1,067,559		367,929
Capitalized interest	44,984		37,920
Capital expenditures, net of sale/leaseback transactions	$	1,653,436	$	1,140,097

(1) Includes capital expenditures related to the Riley Ridge gas plant.

(2) Property acquisitions during the six months endedJune 30, 2013 include capital expenditures of approximately $1.1 billion related to acquisitions during the period that are not reflected as an Investing Activity on our Unaudited Condensed Consolidated Statements of Cash Flows due to the movement of proceeds through a qualified intermediary.  See Note 2, Acquisitions and Divestitures, to the Unaudited Condensed Consolidated Financial Statements.

For the first six months of 2013, our capital expenditures other than those for property acquisitions were funded with $706.7 million of cash flow from operations, and those for property acquisitions were funded with proceeds from the Bakken exchange transaction.  Our capital expenditures for the first six months of 2012 were funded with $732.6 million of cash flow from operations, $210.3 million of net proceeds (after final closing adjustments) from non-core oil and natural gas divestitures, $83.5 million of proceeds from the sale of our investment in Vanguard common units and the remainder with borrowings under our bank credit facility.

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include operating leases for office space and various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet.  In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.

Our commitments and obligations consist of those detailed as of December 31, 2012 in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations, plus estimated obligations related to the Delhi Field release (many of which are contingent and cannot yet be quantified). See Note 7, Commitments and Contingencies, to the Unaudited Condensed Consolidated Financial Statements for further discussion.

RESULTS OF OPERATIONS

Our tertiary operations represent a significant portion of our overall operations and is our primary strategic focus. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play, and we have outlined certain of these differences in our Form 10-K and other public disclosures. Our focus on these types of operations impacts certain trends in both current and long-term operating results. Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Financial Overview of Tertiary Operations in our Form 10-K for further information regarding these matters.

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Denbury Resources Inc.

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

Operating Results Summary

Certain of our operating results and statistics for the comparative second quarters and first six months of 2013 and 2012 are included in the following table:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per share and unit data	2013			2012			2013			2012
Operating results
Net income	$	129,980		$	211,865		$	217,551		$	325,332
Net income per common share – basic	0.35			0.55			0.59			0.84
Net income per common share – diluted	0.35			0.54			0.58			0.83
Net cash provided by operating activities	437,568			440,966			706,744			732,620
Average daily production volumes
Bbls/d	69,895			67,476			64,764			67,167
Mcf/d	24,945			29,163			25,210			28,608
BOE/d (1)	74,052			72,337			68,966			71,934
Operating revenues
Oil sales	$	629,189		$	587,191		$	1,195,332		$	1,210,897
Natural gas sales	8,999			4,950			16,509			14,745
Total oil and natural gas sales	$	638,188		$	592,141		$	1,211,841		$	1,225,642
Commodity derivative contracts (2)
Cash receipt on settlements of derivative contracts	$	—		$	7,282		$	—		$	6,092
Noncash fair value adjustments to derivative contracts – income	45,501			131,827			33,572			87,742
Total income from commodity derivative contracts	$	45,501		$	139,109		$	33,572		$	93,834
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	98.92		$	95.63		$	101.97		$	99.06
Natural gas price per Mcf	3.96			1.87			3.62			2.83
Unit prices – including impact of derivative settlements (2)
Oil price per Bbl	$	98.92		$	95.51		$	101.97		$	98.33
Natural gas price per Mcf	3.96			4.88			3.62			5.72
Oil and natural gas operating expenses
Lease operating expenses (3)	$	220,558		$	124,511		$	361,100		$	262,475
Marketing expenses	13,332			12,218			23,128			23,048
Production and ad valorem taxes	41,049			36,232			76,469			77,287
Oil and natural gas operating revenues and expenses per BOE (1)
Oil and natural gas revenues	$	94.70		$	89.96		$	97.08		$	93.62
Lease operating expenses (3)	32.73			18.92			28.93			20.05
Marketing expenses, net of third-party purchases	1.55			1.26			1.47			1.46
Production and ad valorem taxes	6.09			5.50			6.13			5.90
CO2 revenues and expenses
CO2 sales and transportation fees	$	6,562		$	5,301		$	13,120		$	12,096
CO2 discovery and operating expenses (4)	(3,419		)	(1,062		)	(7,141		)	(7,267		)
CO2 revenue and expenses, net	$	3,143		$	4,239		$	5,979		$	4,829

(1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE"). 

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Denbury Resources Inc.

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

(2) See also Item 3. Quantitative and Qualitative Disclosures about Market Risk below for information concerning the Company's derivative transactions.

(3) Excluding estimated lease operating expense recorded during the second quarter of 2013 to remediate an area of Delhi Field (see Overview – Delhi Field Release above), lease operating expenses totaled $150.6 million and $291.1 million for the three and six months endedJune 30, 2013, respectively and lease operating expense per BOE averaged $22.34 and $23.32 for the three and six months endedJune 30, 2013, respectively.

(4) Includes $0.5 million of exploratory costs during the three and six months ended June 30, 2013 and $4.8 million during the six months ended June 30, 2012. We incurred no exploratory costs during the three months ended June 30, 2012.

Production

Average daily production by area for each of the four quarters of 2012 and for the first and second quarters of 2013 is shown below:

	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Operating Area	2012	2012	2012	2012	2013	2013
Tertiary oil production
Gulf Coast region
Mature properties:
Brookhaven	3,014	2,779	2,460	2,520	2,305	2,339
Eucutta	3,090	2,870	2,782	2,730	2,636	2,642
Mallalieu	2,585	2,461	2,181	2,127	2,116	2,157
Other mature properties (1)	8,012	7,867	7,347	7,605	7,800	7,233
Delhi	4,181	4,023	3,813	5,237	5,827	5,479
Hastings	618	1,913	2,794	3,409	3,956	4,010
Heidelberg	3,583	3,823	3,716	3,930	3,943	4,149
Oyster Bayou	877	1,304	1,540	1,826	2,252	2,518
Tinsley	7,297	8,168	8,153	8,166	8,222	8,225
Total tertiary oil production	33,257	35,208	34,786	37,550	39,057	38,752
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	4,573	4,095	3,401	3,663	3,013	2,367
Texas	3,674	4,573	5,173	5,513	6,692	6,932
Other	1,281	1,306	1,137	1,217	1,153	1,108
Total Gulf Coast region	9,528	9,974	9,711	10,393	10,858	10,407
Rocky Mountain region
Cedar Creek Anticline (2)	8,496	8,535	8,490	8,493	8,745	19,935
Other	3,204	3,060	3,037	3,616	5,163	4,958
Total Rocky Mountain region	11,700	11,595	11,527	12,109	13,908	24,893
Total non-tertiary production	21,228	21,569	21,238	22,502	24,766	35,300
Total continuing production	54,485	56,777	56,024	60,052	63,823	74,052
Properties disposed:
Bakken area assets (3)	15,285	15,503	16,752	10,064	—	—
2012 Non-core asset divestitures (4)	1,762	57	—	—	—	—
Total production	71,532	72,337	72,776	70,116	63,823	74,052

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Denbury Resources Inc.

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

(1) Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.

(2) Beginning March 27, 2013, amounts include production from our purchase of additional interests in the CCA.

(3) Includes production from certain Bakken area assets sold in the fourth quarter of 2012.

(4) Includes production from certain non-core Gulf Coast assets sold in late February 2012 and certain non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah sold in April 2012.

Total Production

Total production increased1,715 BOE/d (2%) between the second quarters of 2012 and 2013, with the most recent quarter including production from CCA assets acquired in late March 2013, while the 2012 quarter included production from our Bakken area assets sold in December 2012 and other non-core assets sold during 2012. The most recent quarter's production levels reflect a return to production levels close to those prior to our fourth quarter 2012 Bakken sale and exchange. On a year-to-date basis, total production decreased2,968 BOE/d (4%) between the first six months of 2012 and 2013, due primarily to the timing of the acquisition of CCA and the divestiture of Bakken area assets noted above. Our production during the three and six months endedJune 30, 2013 was 94% oil, consistent with oil production of 93% during the three and six months endedJune 30, 2012.

Continuing production, which includes production from recently acquired properties and excludes production related to properties sold or exchanged, increased17,275 BOE/d (30%) during the three months ended June 30, 2013 over production levels in the 2012 comparable period, and increased from 55,631 BOE/d during the first six months of 2012 to 68,966 BOE/d during the first six months of 2013 (a 24% increase). Continuing production increases were primarily due to our acquisition of producing assets in the CCA which closed on March 27, 2013. Production from this acquisition contributed approximately 11,300 BOE/d to second quarter 2013 production and approximately 5,900 BOE/d to the first six months' average daily production total for 2013. Continuing production was also impacted by production increases from our tertiary oil fields and incremental production from three fields acquired during 2012, and was partially offset by normal declines in our mature tertiary fields and other non-tertiary fields.

Tertiary Production

Oil production from our tertiary operations increased10% when comparing the second quarters of 2013 and 2012, to 38,752 Bbls/d during the second quarter of 2013. This increase was primarily due to production growth in response to continued field development and expansion of facilities in the tertiary floods in Delhi, Hastings, and Oyster Bayou fields, partially offset by normal declines in our mature tertiary fields. Sequentially, tertiary oil production during the second quarter of 2013decreased305 Bbls/d (1%) compared to production levels in the first quarter of 2013 primarily due to decreased production at Delhi Field and normal declines in our mature tertiary fields, offset by increased production primarily at Oyster Bayou and Heidelberg fields. Production at Delhi Field declined late in the second quarter of 2013 due to steps taken by the Company to stop the flow of well fluids in the field (see Overview – Delhi Field Release above) and production is expected to continue to decline until CO₂ injections to the impacted portion of the field (which were cut off in mid-June) resume. Based on our current analysis of the situation, we expect to resume CO₂ injections into the impacted area of the field in the fourth quarter of 2013. Once CO₂ injections resume, the field's oil production is anticipated to gradually recover. During July 2013, tertiary production at Delhi Field ranged from approximately 4,000 Bbls/d to 4,500 Bbls/d. Costs incurred as a result of the release, together with lower production levels, are currently expected to delay the effective date of a third party's reversionary interest in the Delhi Field until some time during 2014, which we previously estimated would decrease our share of production in Delhi Field by approximately 25% during the latter half of 2013.

Non-Tertiary Production

Continuing production from our non-tertiary operations increased to an average of 35,300 BOE/d during the second quarter of 2013, an increase of 13,731 BOE/d (64%) compared to second quarter2012 non-tertiary continuing production levels and an increase of 10,534 BOE/d (43%) compared to first quarter of 2013 levels. The non-tertiary continuing production increases were primarily due to production from newly acquired fields, specifically CCA acquired in March 2013, Webster and Hartzog Draw fields acquired in the Bakken exchange transaction in late 2012 and Thompson Field acquired in June 2012. With the exception of the impact of production added from fields acquired during 2012 and 2013, production from our other non-tertiary properties is generally on decline, and in some instances the decline may appear larger than normal due to the expansion of our tertiary floods in certain fields which causes non-tertiary production generally to be shut in for a period while the field is being pressured up.

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Denbury Resources Inc.

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

Oil and Natural Gas Revenues

Our oil and natural gas revenues increased 8% during the three months ended June 30, 2013 and decreased 1% during the six months ended June 30, 2013 compared to these revenues for the same periods in 2012.  The increase during the three month period is related to increases in production and commodity prices, and the decrease during the six month period is related to a decrease in production, partially offset by an increase in commodity prices. The change in oil and natural gas revenues due to these factors, excluding any impact of our derivative contracts, is reflected in the following table:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013 vs. 2012				2013 vs. 2012
In thousands	Increase in Revenues		Percentage Increase in Revenues		Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Increase (decrease) in production	$	14,046	2	%	$	(57,034	)	(5	)%
Increase in commodity prices	32,001		6	%	43,233			4	%
Total increase (decrease) in oil and natural gas revenues	$	46,047	8	%	$	(13,801	)	(1	)%

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 the six months ended June 30, 2013 and 2012:

	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
	2013			2012			2013			2012			2013			2012
Net realized prices:
Oil price per Bbl	$	105.59		$	102.52		$	98.92		$	95.63		$	101.97		$	99.06
Natural gas price per Mcf	3.28			3.84			3.96			1.87			3.62			2.83
Price per BOE	99.87			97.32			94.70			89.96			97.08			93.62
NYMEX differentials:
Oil per Bbl	$	11.17		$	(0.37	)	$	4.78		$	2.14		$	7.69		$	0.87
Natural gas per Mcf	(0.21		)	1.32			(0.05		)	(0.49		)	(0.14		)	0.40

As reflected in the table above, our average net realized oil price increased3% during the second quarter of 2013, compared to the average price received during the second quarter of 2012.  Company-wide oil price differentials in the second quarter of 2013 were $4.78 per Bbl above NYMEX, compared to an average differential of $2.14 per Bbl above NYMEX in the second quarter of 2012.  The net differential we received was primarily impacted by positive differentials in the Gulf Coast region, offset by unfavorable differentials in the Rocky Mountain region, each of which is discussed in further detail below.

We received favorable NYMEX oil differentials in the Gulf Coast region during the three and six months endedJune 30, 2013 and 2012, primarily due to the favorable differential for crude oil sold under Light Louisiana Sweet (“LLS”) index prices.  This LLS-to-NYMEX differential averaged a positive $15.07 per Bbl on a trade-month basis for the second quarter of 2013, compared to a positive $18.14 per Bbl differential in the second quarter of 2012 and a positive $20.15 per Bbl in the first quarter of 2013.  Prices received in a regional market can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors and location differentials.  While this differential is significant in the pricing for our oil production, other market and contractual factors may prevent us from realizing the full differential.  The favorable LLS-to-NYMEX differential received in recent periods may not continue. In fact, during late July 2013, the LLS premium to NYMEX had decreased to around $6 positive to NYMEX.

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Denbury Resources Inc.

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

NYMEX oil differentials in the Rocky Mountain region during the second quarter of 2013 were $6.77 per Bbl below NYMEX, compared to an average differential of $15.38 per Bbl below NYMEX in the second quarter of 2012 and $4.49 per Bbl below NYMEX in the first quarter of 2013. The change in the differential between 2012 and 2013 was largely impacted by the sale of our Bakken area assets in December 2012, as oil from the disposed properties sold at a significant discount to NYMEX during 2012, all due to increased production in the area coupled with limited transportation infrastructure.

During the second quarter of 2013, we sold approximately 44% of our crude oil at prices based on the LLS index price, approximately 22% at prices partially tied to the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.  

Oil and Natural Gas Derivative Contracts

The following tables summarize the impact our oil and natural gas derivative contracts had on our operating results for the three and six months endedJune 30, 2013 and 2012:

	Three Months Ended June 30,
	2013		2012			2013		2012			2013		2012
In thousands	Crude Oil Derivative Contracts					Natural Gas Derivative Contracts					Total Commodity Derivative Contracts
Cash settlement receipts (payments)	$	—	$	(709	)	$	—	$	7,991		$	—	$	7,282
Noncash fair value gain (loss)	45,501		140,923			—		(9,096		)	45,501		131,827
Total	$	45,501	$	140,214		$	—	$	(1,105	)	$	45,501	$	139,109

	Six Months Ended June 30,
	2013		2012			2013		2012			2013		2012
In thousands	Crude Oil Derivative Contracts					Natural Gas Derivative Contracts					Total Commodity Derivative Contracts
Cash settlement receipts (payments)	$	—	$	(8,939	)	$	—	$	15,031		$	—	$	6,092
Noncash fair value gain (loss)	33,572		98,478			—		(10,736		)	33,572		87,742
Total	$	33,572	$	89,539		$	—	$	4,295		$	33,572	$	93,834

Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our oil and natural gas derivative contracts.  Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period change in the fair value of these contracts, as outlined above, are recognized in our statements of operations. Our derivative contracts for 2013 and beyond are currently all NYMEX and LLS oil contracts given that our current and forecasted production is primarily oil (94% of volumes on a BOE-basis in the second quarter of 2013), leading us to focus at the current time solely on oil derivative contracts in our commodity market risk management program. We may enter into natural gas derivative contracts in the future as the natural gas market improves and as we anticipate our natural gas production will increase with the expected startup of Riley Ridge gas production later this year. See Notes 5 and 6 to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

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Denbury Resources Inc.

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

Production Expenses

Lease operating expense

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data	2013		2012		2013		2012
Lease operating expense
Tertiary	$	152,941	$	73,527	$	239,749	$	154,458
Non-tertiary	67,617		50,984		121,351		108,017
Total lease operating expense	$	220,558	$	124,511	$	361,100	$	262,475
Lease operating expense per BOE
Tertiary (1)	$	43.37	$	22.95	$	34.05	$	24.79
Non-tertiary	21.05		15.09		22.30		15.74
Total lease operating expense per BOE (1)	32.73		18.92		28.93		20.05

(1) Excluding estimated lease operating expense recorded during the second quarter of 2013 to remediate an area of Delhi Field (see Overview – Delhi Field Release above), tertiary lease operating expenses per BOE averaged $23.52 and $24.11 for the three and six months endedJune 30, 2013, respectively and total lease operating expense per BOE averaged $22.34 and $23.32 for the three and six months endedJune 30, 2013, respectively.

Total lease operating expense during the three and six months endedJune 30, 2013increased from the comparable 2012 periods on an absolute-dollar and per-BOE basis primarily due to $70.0 million in estimated lease operating expenses recorded during the second quarter of 2013, which represents our current estimate of the minimum amount to remediate an area of Delhi Field impacted by a release of well fluids discovered in mid-June (see Overview – Delhi Field Release above). Excluding these estimated remediation expenses, lease operating expense increased $26.0 million and $28.6 million, respectively, during the three and six months endedJune 30, 2013 compared to the same periods in 2012 due primarily to increased expenses resulting from our acquisition of additional interests in CCA late in the first quarter of 2013, expansion of our CO₂ floods, increased CO₂ expenses due to an increase in CO₂ volumes injected into producing CO₂ fields and increases in the cost of CO₂ between the comparative periods. Excluding the estimated Delhi Field remediation costs recorded during the second quarter of 2013, lease operating expense increased $3.42 and $3.27 per BOE for the three and six months endedJune 30, 2013, respectively, compared to the comparable prior year periods. The increase in each period is primarily due to the sale of the Bakken assets in late 2012, which had a low operating cost per BOE, and the addition of Hartzog Draw and Webster fields, and additional interests in the CCA, which have a higher operating cost per BOE than the Bakken assets.

Tertiary lease operating expense increased$79.4 million and $85.3 million during the three and six months endedJune 30, 2013 compared to those in the same periods in 2012 due primarily to an accrual of $70.0 million for estimated minimum expenses we expect to incur to remediate Delhi Field (see Overview – Delhi Field Release above). Excluding the estimated Delhi Field remediation expense, tertiary lease operating expense increased $9.4 million and $15.3 million, respectively, during the three and six months endedJune 30, 2013 compared to the same periods in 2012. These increases were primarily a result of the expansion of our CO₂ floods and increased CO₂ expenses due to an increase in CO₂ volumes injected into producing CO₂ fields and increases in the cost of CO₂ between the comparative periods.

Currently, our CO₂ expense comprises approximately one-fourth of our typical Gulf Coast tertiary operating expenses, and for the CO₂ reserves we already own, consists of our CO₂ production expenses, and for the CO₂ reserves we do not own, consists of our purchase of CO₂ from royalty and working interest owners and anthropogenic (man-made) sources. During the second quarter of 2013, approximately 74% of the CO₂ utilized in our Gulf Coast region CO₂ floods consisted of CO₂ owned and produced by us and the remaining portion we purchased from third-party owners (primarily royalty owners). The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production cost of the CO₂ we own with what

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Denbury Resources Inc.

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

we pay third parties for CO₂, our average cost of CO₂ for the Gulf Coast region during the second quarter of 2013 was approximately $0.30 per Mcf, including taxes paid on CO₂ production but excluding depreciation and amortization of capital expended at our Jackson Dome source and CO₂ pipelines. This rate during the second quarter of 2013 was higher than the $0.29 per Mcf spent during the second quarter of 2012. Including the cost of depreciation and amortization expense related to the Jackson Dome CO₂ production but excluding depreciation of our CO₂ pipelines, our cost of CO₂ was $0.40 per Mcf and $0.36 per Mcf during the second quarter of 2013 and 2012, respectively.

Tertiary lease operating expense averaged $43.37 and $34.05 per Bbl during the three and six months endedJune 30, 2013, respectively, compared to $22.95 and $24.79 per Bbl for the comparable prior-year period. The increase in tertiary operating costs per barrel in the second quarter of 2013 compared to the same period in 2012 is due primarily to the expense for estimated remediation costs at Delhi Field. Excluding the estimated Delhi remediation expense, tertiary operating expense averaged $23.52 and $24.11 per Bbl during the three and six months endedJune 30, 2013, representing a 2%increase and 3%decrease per Bbl, respectively, compared to the same periods in 2012.

Non-tertiary lease operating expense increased33% and 12% on an absolute-dollar basis during the three and six months endedJune 30, 2013, respectively, compared to the same prior-year periods, as declines resulting from the sale of our Bakken area assets were more than offset by increases in newly acquired fields, including Thompson field acquired in June 2012, Webster and Hartzog Draw fields acquired in the Bakken exchange transaction in late 2012, and CCA acquired in March 2013. On a per-BOE basis, non-tertiary lease operating expense during the three and six months endedJune 30, 2013increased39% and 42%, respectively, compared to the same prior-year periods due to increases in newly acquired fields, which have a higher operating cost per barrel.

Taxes other than income

Taxes other than income includes ad valorem, production and franchise taxes. Taxes other than income increased $6.1 million and $0.4 million during the three and six months endedJune 30, 2013, respectively, compared to the same periods in 2012. The change in each period is generally aligned with fluctuations in oil and natural gas revenues. The increase during both comparative periods is further impacted by the change in the mix of properties subject to production and ad valorem taxes as a result of the Bakken exchange transaction and CCA acquisition.

General and Administrative Expenses (“G&A”)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per-BOE data and employees	2013			2012			2013			2012
Gross administrative costs	$	80,511		$	71,739		$	164,518		$	145,798
Gross stock-based compensation	9,996			9,364			20,759			19,958
Operator labor and overhead recovery charges	(43,398		)	(34,382		)	(81,792		)	(70,006		)
Capitalized exploration and development costs	(13,727		)	(11,895		)	(28,214		)	(24,317		)
Net G&A expense	$	33,382		$	34,826		$	75,271		$	71,433
G&A per BOE:
Net administrative costs	$	3.89		$	4.27		$	4.88		$	4.41
Net stock-based compensation	1.06			1.02			1.15			1.05
Net G&A expense	$	4.95		$	5.29		$	6.03		$	5.46
Employees as of June 30	1,544			1,414			1,544			1,414

Net G&A expense decreased4% on an absolute-dollar basis and 6% on a per-BOE basis between the three months ended June 30, 2012 and June 30, 2013, and increased5% on an absolute-dollar basis and 10% on a per-BOE basis between the six months ended June 30, 2012 and June 30, 2013.

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Denbury Resources Inc.

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

Gross administrative costs increased$8.8 million (12%) and $18.7 million (13%) during the three and six months endedJune 30, 2013, respectively, compared to the same periods in 2012.  The increase between the comparative three- and six-month periods was primarily due to higher compensation-related costs driven primarily from an increase in headcount (9%) and annual merit increases.

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well.  In addition, salaries associated with field personnel are initially recorded as gross administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production, exploration, and development activities. As a result of additional operated wells, increased compensation expense and an increase in the COPAS overhead rate, the amount we recovered as operator labor and overhead charges increased by 26% and 17% during the three and six months endedJune 30, 2013, respectively, compared to the amounts recovered in the same periods in 2012.  Capitalized exploration and development costs increased between the periods, primarily due to increased compensation costs subject to capitalization.

Interest and Financing Expenses

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per-BOE data and interest rates	2013			2012			2013			2012
Cash interest expense	$	50,478		$	56,376		$	104,480		$	108,409
Noncash interest expense	3,403			3,703			7,140			7,429
Less: Capitalized interest	(23,279		)	(18,475		)	(44,984		)	(37,920		)
Interest expense, net	$	30,602		$	41,604		$	66,636		$	77,918
Interest expense, net per BOE	$	4.54		$	6.32		$	5.34		$	5.95
Average debt outstanding	$	3,271,282		$	2,964,121		$	3,250,401		$	2,854,523

Average interest rate ⁽¹⁾ 6.2 % 7.6 % 6.4 % 7.6 %

(1) Includes commitment fees but excludes debt issue costs and amortization of discount or premium.

Interest expense, net decreased26% and 14% between the three and six months endedJune 30, 2013, respectively, compared to the same periods in 2012. The decrease in interest expense is due to higher capitalized interest, a lower average interest rate, and decreased borrowings on our bank credit facility.  The decrease in the average interest rate is a result of refinancing our 9½% Notes and 9¾% Notes with our 2023 Notes, which carry a rate of 4 5/8% (see Overview – Debt Refinancing above).  The increase in capitalized interest between the three and six months endedJune 30, 2012 and 2013 relates primarily to incremental capitalized interest on construction projects, as well as capitalized interest on enhanced oil recovery development projects.

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Denbury Resources Inc.

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

Depletion, Depreciation and Amortization ("DD&A")

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data	2013		2012		2013		2012
Depletion and depreciation of oil and natural gas properties	$	99,927	$	109,279	$	185,106	$	216,334
Depletion and depreciation of CO2 properties	6,932		5,427		14,269		10,537
Asset retirement obligations	2,116		1,829		4,220		3,524
Depreciation of other fixed assets	17,932		15,754		36,210		22,789
Total DD&A	$	126,907	$	132,289	$	239,805	$	253,184
DD&A per BOE:
Oil and natural gas properties	$	15.14	$	16.88	$	15.16	$	16.79
CO2 and other fixed assets	3.68		3.22		4.04		2.55
Total DD&A cost per BOE	$	18.82	$	20.10	$	19.20	$	19.34

We adjust our DD&A rate each quarter for significant changes in our estimates of oil and natural gas reserves and costs. In addition, under full cost accounting rules, the divestiture of oil and gas properties generally does not result in gain or loss recognition; instead, the proceeds of the disposition reduce the full cost pool. As such, our DD&A rate has changed significantly over time, and it may continue to change in the future.  Depletion and depreciation of oil and natural gas properties decreased9% and 14% on an absolute-dollar basis for the three and six months endedJune 30, 2013, respectively, and decreased 10% on a per-BOE basis during both the three and six months endedJune 30, 2013, compared to the same periods in 2012. These decreases were primarily due to the sale and exchange of our Bakken area assets for other property interests in late 2012, partially offset by the impact of the CCA acquisition in March 2013. As a result of this exchange, there was a net decrease in costs subject to depletion, partially offset by a reduction in total proved reserves.

Depletion and depreciation of our CO₂ properties and other fixed assets increased on an absolute-dollar and per-BOE basis during the three and six months ended June 30, 2013 compared to the same periods in 2012 primarily due to an increase in CO₂ properties, pipelines and plants subject to depreciation as a result of continued development. The increase during the six months ended June 30, 2013 was further impacted by a change in classification of our equipment leases from operating to capital during the second quarter of 2012, and the amount on a per-BOE basis was also impacted by lower oil and natural gas production during the first quarter of 2013. See Note 5, Long-term Debt, of our 2012 Consolidated Financial Statements in the Form 10-K for further discussion of the change in classification of our equipment leases. On a sequential-quarter basis, second quarter of 2013 depletion of CO₂ properties decreased on an absolute-dollar basis from first quarter of 2013 levels due to an increase in CO₂ reserves during the current period as a result of successful drilling in the Jackson Dome area and decreased on a per-BOE basis primarily due to increased oil production during the second quarter of 2013.

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, 2013; however, if oil or natural gas prices were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost pool ceiling test in the future.  The possibility and amount of any future write-down is difficult to predict, and will depend, in part, 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, as well as additional capital spent.

Impairment of Assets

We recognized $17.5 million of impairment charges during the six months ended June 30, 2012, primarily related to our investment in Faustina Hydrogen Products LLC, an entity created to develop a proposed plant from which we could offtake CO₂, as a result of the project not moving forward.  See Note 6, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

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

Income Taxes

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per-BOE amounts and tax rates	2013			2012			2013			2012
Current income tax expense (benefit)	$	(3,171	)	$	784		$	7,348		$	29,492
Deferred income tax expense	84,497			130,152			128,342			167,289
Total income tax expense	$	81,326		$	130,936		$	135,690		$	196,781
Average income tax expense per BOE	$	12.07		$	19.89		$	10.87		$	15.03
Effective tax rate	38.5		%	38.2		%	38.4		%	37.7		%

Our income taxes are based on estimated statutory rates of approximately 38.5% and 38% in 2013 and 2012, respectively.  Our effective tax rate for the three months ended June 30, 2013 and 2012, and the six months endedJune 30, 2013, was comparable to the estimated statutory rate; however, during the six months ended June 30, 2012, the effective rate was lower due to the utilization of a larger amount of preferential tax benefits due to the sale of an investment in that period. The Company recorded a current income tax benefit during the second quarter of 2013 in recognition of an increase in its estimate of tax benefits expected to be received during 2013.

As of June 30, 2013, we had an estimated $17.3 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits that can be utilized to reduce our current income taxes during 2013 or future years, but cannot be used to offset alternative minimum tax.  The enhanced oil recovery credits do not begin to expire until 2025.  Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we do not currently expect to earn additional enhanced oil recovery credits unless oil prices were to significantly deteriorate.

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Denbury Resources Inc.

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

Per-BOE Data

The following table summarizes our cash flow 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	2013			2012			2013			2012
Oil and natural gas revenues	$	94.70		$	89.96		$	97.08		$	93.62
Gain on settlements of derivative contracts	—			1.10			—			0.47
Lease operating expenses	(32.73		)	(18.92		)	(28.93		)	(20.05		)
Production and ad valorem taxes	(6.09		)	(5.50		)	(6.13		)	(5.90		)
Marketing expenses, net of third party purchases	(1.55		)	(1.26		)	(1.47		)	(1.46		)
Production netback	54.33			65.38			60.55			66.68
CO2 sales, net of operating and exploration expenses	0.46			0.65			0.48			0.36
General and administrative expenses	(4.95		)	(5.29		)	(6.03		)	(5.46		)
Interest expense, net	(4.54		)	(6.32		)	(5.34		)	(5.95		)
Other	0.54			0.55			0.39			(1.10		)
Changes in assets and liabilities relating to operations	19.09			12.02			6.57			1.42
Cash flow from operations	64.93			66.99			56.62			55.95
DD&A	(18.82		)	(20.10		)	(19.20		)	(19.34		)
Deferred income taxes	(12.54		)	(19.77		)	(10.28		)	(12.78		)
Loss on early extinguishment of debt	(0.06		)	—			(3.58		)	—
Noncash commodity derivative adjustments	6.75			20.03			2.69			6.70
Impairment of assets	—			(0.03		)	—			(1.34		)
Other noncash items	(20.97		)	(14.93		)	(8.82		)	(4.34		)
Net income	$	19.29		$	32.19		$	17.43		$	24.85

CRITICAL ACCOUNTING POLICIES

Environmental and Litigation Contingencies

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors.  Actual costs can vary from such estimates for a variety of reasons.  The costs of environmental remediation or litigation can vary from estimates due to new developments regarding the facts and circumstances of each event, including in the case of environmental remediation, the timing of remediation, our understanding of the environmental impact, remediation methods available, and regulatory requirements, and in the case of litigation, differing interpretations of laws and facts and assessments of damages asserted and/or incurred.

Other Critical Accounting Policies

For discussion of our other critical accounting policies, which remain unchanged, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Form 10-K.

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Denbury Resources Inc.

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

FORWARD-LOOKING INFORMATION

The statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section 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 Exchange Act of 1934, as amended (the "Exchange Act"), that involve a number of risks and uncertainties.  Such forward-looking statements may be or may concern, among other things, forecasted cash flows and capital expenditures, drilling activity or methods including the timing and location thereof, pending or planned acquisitions or dispositions, development activities, timing of CO₂ injections and initial production responses thereto, cost savings, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves, helium reserves, potential reserves, percentages of recoverable original oil in place, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices, cost and availability of equipment and services, liquidity, availability of capital, borrowing capacity, regulatory matters, prospective legislation affecting the oil and gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, estimates of the range of potential insurance recoveries, minimum estimates of costs of remedial activities, changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may,” or other words that convey, or are intended to 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 and adversely affect current plans, anticipated actions, the timing of such actions and the Company’s 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 or on behalf of the Company.  Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil and/or natural gas prices and consequently in the prices received or demand for the Company’s oil and natural gas; levels of future capital expenditures; 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; operating hazards and remediation costs; disruption of operations and damages from well damage, hurricanes, tropical storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial and credit markets; general economic conditions; competition; government regulations, including tax and environmental; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings and public statements including, without limitation, the Form 10-K.

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Denbury Resources Inc.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Long-term Debt and Interest Rate Sensitivity

We finance some of our acquisitions and other expenditures with fixed and variable rate debt.  These debt agreements expose us to market risk related to changes in interest rates. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies, although under the NEJD financing lease, in the event of significant downgrades of our corporate credit rating by the rating agencies, certain credit enhancements can be required from us, and possibly other remedies made available under the lease.  As of June 30, 2013, our borrowings on our bank credit facility were $260.0 million, with a weighted average interest rate of 1.7%.  At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense.

The following table presents the principal balances of our debt, by maturity date, as of June 30, 2013:

In thousands	2014		2015		2016		2017		2020		2021		2023		Total
Variable rate debt:
Bank Credit Facility (weighted average interest rate of 1.7% at June 30, 2013)	$	—	$	—	$	260,000	$	—	$	—	$	—	$	—	$	260,000
Fixed rate debt:
8¼% Senior Subordinated Notes due 2020	—		—		—		—		996,273		—		—		996,273
6 3/8% Senior Subordinated Notes due 2021	—		—		—		—		—		400,000		—		400,000
4 5/8% Senior Subordinated Notes due 2023													1,200,000		1,200,000
Other Subordinated Notes	1,072		485		—		2,250		—		—		—		3,807

Oil and Natural Gas Derivative Contracts

We regularly enter into oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production.  We do not hold or issue derivative financial instruments for trading purposes.  These contracts have consisted of price floors, collars and fixed price swaps.  The production that we hedge has varied from year to year, depending on our levels of debt and financial strength and expectation of future commodity prices.  We currently employ a strategy to hedge a portion of our forecasted production for approximately two years in the future from the current quarter, as we believe it is important to protect our future cash flow for a period of time in order to give us time to adjust to commodity price fluctuations, particularly since many of our planned expenditures have long lead times.  Because our current and forecasted production is primarily oil (94% of volumes on a BOE-basis during the second quarter of 2013), we currently hold only oil derivative contracts in our commodity market risk management program. We may enter into natural gas derivative contracts in the future as the natural gas market improves and as we anticipate our natural gas production to increase with the expected startup of Riley Ridge gas production later this year. See Notes 5 and 6to 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.  We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification.  All of our commodity derivative contracts are with parties that are lenders under our bank credit facility.  We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

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Denbury Resources Inc.

For accounting purposes, we do not apply hedge accounting to our oil and natural gas 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, 2013, our derivative contracts were recorded at their fair value, which was a net asset of approximately $26.6 million, a $33.5 million increase from the $6.9 million net liability recorded at December 31, 2012.  This change is primarily related to the expiration of oil derivative contracts during 2013 and to changes in oil futures prices between December 31, 2012 and June 30, 2013.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of June 30, 2013, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil derivative contracts as shown in the following table:

In thousands	Receipt/ (Payment)
Based on:
Futures prices as of June 30, 2013	$	—
10% increase in prices	(15,955		)
10% decrease in prices	22,271

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Denbury Resources Inc.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer.  Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2013, to ensure that information required to be disclosed in the reports the Company files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the second quarter of fiscal 2013, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Denbury Resources Inc.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Although not material to the Company's business or financial condition, the description herein of a fine to be paid to Mississippi environmental regulators is being provided under Instruction 5.C. of Item 103 of Regulation S-K pertaining to administrative proceedings arising under state environmental laws on discharge of materials into the environment which involve monetary sanctions in excess of $100,000: On June 20, 2013, the Company entered into an Agreed Order with the Mississippi Commission on Environmental Quality related to a notice of violation for a release of fluids at the Tinsley Field in the third quarter of 2011, under which order the Company agreed to pay a $662,500 fine as a civil penalty related to the release.

Item 1A. Risk Factors

Information with respect to the risk factors has been incorporated by reference to Item 1A of the Form 10-K.  There have been no material changes to the risk factors since the filing of the 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 2013:

Month	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (1)
April 2013	800,559	$	17.40	790,874	$	229.3
May 2013	321,731	17.54		301,353	224.1
June 2013	15,946	17.79		—	224.1
Total	1,138,236	17.45		1,092,227	224.1

(1) In October 2011, the Company's Board of Directors approved a share repurchase program for up to $500 million of Denbury's common stock, which was increased by an additional $271.2 million in early November 2012.

Between early October 2011, when we announced the commencement of a common share repurchase program and June 30, 2013, we repurchased 36.1 million shares of Denbury common stock (approximately 9.0% of our outstanding shares of common stock at September 30, 2011) for $547.1 million, or $15.15 per share. The program has no pre-established ending date and may be suspended or discontinued by our Board of Directors at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

All other repurchases of our common stock during the second quarter of 2013 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights.

Item 3. Defaults upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

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Denbury Resources Inc.

Item 5. Other Information

None

Item 6. Exhibits

Exhibit No.	Exhibit
10(a)	Denbury Resources Inc. Amended and Restated Employee Stock Purchase Plan, effective as of May 22, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 28, 2013, File No. 001-12935).
10(b)	Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated effective as of May 22, 2013 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on May 28, 2013, File No. 001-12935).
10(c)*	Form of Restricted Share Award for Non-Employee Directors under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(d)*	Form of Deferred Stock Unit Award (with respect to Deferred Long-Term Incentive Awards) for Non-Employee Directors under the Director Deferred Compensation Plan for Denbury Resources Inc.
10(e)*	Form of Deferred Stock Unit Award (with respect to Deferred Director Fees) for Non-Employee Directors under the Director Deferred Compensation Plan for Denbury Resources Inc.
31(a)*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data Files.

* Included herewith.

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Denbury Resources Inc.

SIGNATURES

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

	DENBURY RESOURCES INC.
August 6, 2013	/s/ Mark C. Allen
	Mark C. Allen Sr. Vice President and Chief Financial Officer
August 6, 2013	/s/ Alan Rhoades
	Alan Rhoades Vice President and Chief Accounting Officer

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Denbury Resources Inc.

INDEX TO EXHIBITS

Exhibit No.	Exhibit
10(c)	Form of Restricted Share Award for Non-Employee Directors under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
10(d)	Form of Deferred Stock Unit Award (with respect to Deferred Long-Term Incentive Awards) for Non-Employee Directors under the Director Deferred Compensation Plan for Denbury Resources Inc.
10(e)	Form of Deferred Stock Unit Award (with respect to Deferred Director Fees) for Non-Employee Directors under the Director Deferred Compensation Plan for Denbury Resources Inc.
31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data Files.

- 39 -

EX-10.C

Exhibit 10(c)

__________ Restricted Shares    Date of Grant: __________

RESTRICTED SHARE AWARD

CLIFF VESTING AWARDS

2004 OMNIBUS STOCK AND INCENTIVE PLAN

FOR DENBURY RESOURCES INC.

RESTRICTED SHARE AWARD (“Award”) made effective _________ (“Date of Grant”) between Denbury Resources Inc. (the “Company”) and _______________ (“Holder”), a non-employee member of the Board of Directors (“Board”) of the Company.

WHEREAS, the Company desires to grant to the Holder______________________ Restricted Shares under and for the purposes of the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (Amended and Restated as of May 22, 2013), and as may be further amended (the “Plan”);

WHEREAS, in accordance with the provisions of Section 16(d) of the Plan, the Restricted Shares will be issued by the Company in the Holder's name and be issued and outstanding for all purposes (except as provided below or in the Plan) but held by the Company (together with the stock power set forth below) until such time as such Restricted Shares are Vested by reason of the lapse of the applicable Restrictions, after which time the Company shall make delivery of the Vested Shares to Holder;

WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan, and all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award; and

WHEREAS, terms capitalized but not defined above (or otherwise) in this Award will have the meaning given to such terms under the Plan.

NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the parties agree as follows:

1.Restricted Share Award. The Company hereby sells, transfers, assigns and delivers to the Holder an aggregate of ___________________ Restricted Shares (“Award Restricted Shares”) on the terms and conditions set forth in the Plan and as supplemented in this Award, including, without limitation, the restrictions more specifically set forth in Section 2 below, subject only to Holder's execution of this Award agreement.

2.Vesting of Award Restricted Shares. The Restrictions on the Award Restricted Shares shall lapse (Award Restricted Shares with respect to which Restrictions have lapsed being herein referred to as “Vested Shares”) and become fully non-forfeitable on the occurrence of the earliest of the dates set forth in (a) through (d) below and partially non-forfeitable on a Pro Rata Basis (as defined below) as provided in (e) and (f) below (“Vesting Dates”):

(a) [the day immediately preceding the one-year anniversary of the Date of Grant] (“Anniversary Date”);

(b) the date of Holder's death or Disability;

(c) the date of a Change in Control; and

(d) the date of a Post-Separation Change in Control.

A-1

For purposes of this Award, the term “Post-Separation Change in Control” means a Change in Control which follows the Holder's Separation, but results from the Commencement of a Change in Control that occurs prior to the Holder's Separation. For all purposes of this Award, the term “Commencement of a Change in Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates.

In addition to the Vesting Dates provided in (a) through (d) above, the Holder shall have Vested Shares which become non-forfeitable on a Pro Rata Basis (as defined below) on the date of the Holder's Separation (such date to be an additional Vesting Date), but only if the Holder:

(e) incurs a Separation before the Anniversary Date (such date being the “Separation Date”); and

(f) such Separation does not constitute a Separation for Cause or is not the result of conduct which could have otherwise led to a Separation for Cause.

For purposes of this Award, “Pro Rata Basis” means the product of (g) multiplied by a fraction of (h) divided by (i) on such Vesting Date, such product being rounded to the nearest whole Share, where:

(g) equals the total number of Award Restricted Shares granted under this Award;

(h) equals the number of days the Holder provided services as a Director during the Restricted Period up to and including the Separation Date (numerator); and

(i) equals the total number of days during the Restricted Period beginning on the date the Holder began providing services as a Director and ending on the Anniversary Date (denominator).

3.Restrictions - Forfeiture of Award Restricted Shares. The Award Restricted Shares are subject to the Restriction that, except as provided in the following sentence, all rights of Holder to any Award Restricted Shares which have not become Vested Shares automatically, and without notice, shall terminate and shall be permanently forfeited on the date of Holder's Separation. The exception referred to in the preceding sentence is that, if there is a Post-Separation Change in Control, the previously forfeited Award Restricted Shares shall be reinstated as Vested Shares and, for all purposes of this Award, Holder will be deemed to have Separated on the day after such Post-Separation Change in Control.

4.Withholding. There will be no tax withholding with respect to this Award.

5.Issuance of Shares. Without limitation, Holder shall have all of the rights and privileges of an owner of the Award Restricted Shares (including voting rights) except that Holder shall not be entitled to delivery of the certificates evidencing any of the Shares unless and until they become Vested Shares, nor shall Holder be entitled to receive Restricted Share Distributions (i.e., dividends) until they become Vested Shares. The Administrator shall deliver the Vested Shares to the Holder as soon as reasonably possible following vesting. The Holder agrees to hold and retain the required number of Vested Shares as specified in the Company's stock ownership guidelines, as potentially modified from time to time.

6.No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Shares.

7.No Right To Continued Board Service.Neither the Plan nor this Award shall confer upon the Holder any right to continue to serve as a Director, nor shall they interfere in any way with Holder's right to resign or otherwise terminate participation on the Board.

8.Governing Law. Without limitation, this Award shall be construed and enforced in accordance with and governed by the laws of Delaware.

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9.Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto.

10.Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.

11.Committee Authority. The Award shall be administered by the Committee, which shall adopt rules and regulations for carrying out the purposes of the Award and, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to the Administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.

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IN WITNESS WHEREOF, the Company has caused these presents to be executed on its behalf and its corporate seal to be affixed hereto by its duly authorized representative and the Holder has hereunto set his or her hand and seal, all on the day and year first above written.

	DENBURY RESOURCES INC.
Per:
	Phil Rykhoek, Chief Executive Officer
Per:
	Mark Allen, SVP & Chief Financial Officer

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Assignment Separate From Certificate

FOR VALUE RECEIVED, the undersigned hereby sells, assigns and transfers unto Denbury Resources Inc. the ________________ Award Restricted Shares subject to this Award, standing in the undersigned's name on the books of said Denbury Resources Inc., and do hereby irrevocably constitute and appoint the corporate secretary of Denbury Resources Inc. as attorney to transfer the said stock on the books of Denbury Resources Inc. with full power of substitution in the premises.

Dated as of this ________ day of ______________, ______.

______________________________

Holder Signature

Acknowledgment

The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan.

Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or this Award, or both) of the Administrator upon any questions arising under the Plan, or this Award, or both.

Dated as of this ________ day of ______________, ______.

______________________________

Holder Signature

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EX-10.D

Exhibit 10(d)

________ Deferred Stock UnitsDate of Grant: ___________

DEFERRED STOCK UNIT AWARD

DENBURY RESOURCES INC.

DIRECTOR DEFERRED COMPENSATION PLAN

(WITH RESPECT TO DEFERRED LONG TERM INCENTIVE AWARDS)

DEFERRED STOCK UNIT AWARD (“Award”) made effective _____________ (“Date of Grant”) between Denbury Resources Inc. (“Company”) and _______________ (“Holder”), a non-employee member of the Board of Directors (“Board”) of the Company.

WHEREAS, the Holder completed a Long Term Incentive Award Deferral Election Form with respect to the directly preceding calendar year (“Election”), pursuant to Section 8(b) of the Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated on December 13, 2012, and as may be further amended (“Plan”), and timely filed such Election with the Company as required under the Plan with respect to the directly preceding calendar year for services rendered as a Board member during the current calendar year;

WHEREAS, consistent with any Election made by the Holder, the Company desires to grant the Holder a certain number of Deferred Stock Units set forth below for services rendered by the Holder to the Company as a member of the Board in accordance with the terms of the Plan (“Award Units”), substantially equal in value to an equivalent number of whole shares of “Common Stock” (as defined below) on the date of grant of this Award set forth below (“Date of Grant”), which vested Deferred Stock Units shall be paid as specified in this Award and the Plan;

WHEREAS, for purposes of this Award, “Common Stock” means shares of the common stock of the Company that are registered by the Company under the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (Amended and Restated as of May 22, 2013), and as may be further amended (“Incentive Plan”);

WHEREAS, notwithstanding the directly preceding concerning the Incentive Plan, the Company and Holder understand and agree that the provisions of the Incentive Plan shall not apply to this Award, except as explicitly provided in the Plan;

WHEREAS, in accordance with the provisions of Section 8(a)(2) of the Plan, the Award Units subject to this Award will be issued by the Company in the Holder's name and credited to the Holder's Deferred Stock Unit Account under the Plan until such time as a Distribution Event occurs, after which time any vested Award Units shall be payable in Common Stock in accordance with the terms of this Award and the Plan;

WHEREAS, the Company and Holder understand and agree that this Award is in all respects subject to the terms, definitions and provisions of the Plan and the applicable Election, all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Award; and

WHEREAS, terms capitalized but not defined above (or otherwise) in this Award will have the meaning given to such terms under the Plan.

NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the Company and Holder agree as follows:

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1.Award Units. The Company hereby grants to the Holder an aggregate of _____________________on the Date of Grant on the terms and conditions set forth in the Plan and as supplemented by the terms of this Award, including, without limitation, the vesting provisions set forth in Section 2. below and the distribution provisions set forth in Section 6. below, subject only to Holder's execution of this Award. Such Award Units shall be credited to the Holder's Deferred Stock Unit Account. As soon as practicable thereafter, a report shall be provided to the Holder setting forth the number of Award Units granted to the Holder. The Award Units shall be adjusted from time to time as provided in the Plan.

2.Vesting of Award Units. The Award Units shall vest and become non-forfeitable (Award Units which have become vested being herein referred to as “Vested Units”) on the occurrence of the earliest of the dates (“Vesting Date”) set forth in (a) through (d) immediately below:

(a) [the day immediately preceding the one-year anniversary of the Date of Grant] (“Anniversary Date”);

(b) the date of Holder's Separation by reason of death or Disability;

(c) the date of a Change in Control; and

(d) the date of a Post-Separation Change in Control.

For purposes of this Award, the term “Post-Separation Change in Control” means a Change in Control which follows the Holder's Separation, but results from the Commencement of a Change in Control that occurs prior to the Holder's Separation. For all purposes of this Award, the term “Commencement of a Change in Control” shall mean the date on which any material action, including without limitation through a written offer, open-market bid, corporate action, proxy solicitation or otherwise, is taken by a “person” (as defined in Section 13(d) or Section 14(d)(2) of the 1934 Act), or a “group” (as defined in Section 13(d)(3) of the 1934 Act), or their affiliates, to commence efforts that, within 12 months after the date of such material action, leads to a Change in Control as defined in Section 2(h)(2), (3) or (4) of the Plan involving such person, group, or their affiliates.

In addition to the Vesting Dates provided in (a) through (d) above, the Holder shall have Vested Units which become non-forfeitable on a Pro Rata Basis (as defined below) on the date of the Holder's Separation (such date to be an additional Vesting Date), but only if the Holder:

(e) incurs a Separation before the Anniversary Date (such date being the “Separation Date”); and

(f) such Separation does not constitute a Separation for Cause or is not the result of conduct which could have otherwise led to a Separation for Cause.

For purposes of this Award, “Pro Rata Basis” means the product of (g) multiplied by a fraction of (h) divided by (i) on such Vesting Date, such product being rounded to the nearest whole Share, where:

(g) equals the total number of Award Units granted under this Award;

(h) equals the number of days the Holder provided services as a Director during the Restricted Period up to and including the Separation Date (numerator); and

(i) equals the total number of days during the Restricted Period beginning on the date the Holder began providing services as a Director and ending on the Anniversary Date (denominator).

3.Forfeiture of Award Units. Except as otherwise provided in this Award, all rights of Holder to any Award Units which have not become Vested Units shall automatically, and without notice, terminate and be permanently

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forfeited on the date of Holder's Separation (other than by death or Disability). Notwithstanding the immediately foregoing sentence, if there is a Post-Separation Change in Control, the previously forfeited Award Units shall be reinstated as Vested Units and, for all purposes of this Award, Holder will be deemed to have Separated immediately after such Change in Control.

4.    Withholding and Taxes. There will be no tax withholding with respect to this Award. The Award is not subject to Section 83 of the Code, relating to certain transfers of property, and Holder agrees and warrants that Holder will not make an election under Section 83(b) with respect to the Award.

5.    Section 409A of the Code. The Company and Holder intend that this Award will be administered in accordance with Section 409A of the Code by the Committee. To the extent that any provision of this Award is ambiguous as to its compliance with Section 409A of the Code, the provision shall be read by the Committee in such a manner so that all payments hereunder comply with (or are exempt from, as appropriate) Section 409A of the Code. The Holder agrees that this Award may be amended unilaterally by the Company, as may be reasonably requested by either party, and as may be necessary to fully comply with Section 409A of the Code (and all related rules and regulations) in order to preserve the tax treatment to the extent possible of any payments and benefits provided by this Award. Notwithstanding the foregoing, the Company makes no representation or warranty, and the Holder acknowledges and agrees that the Company, the Board, the Committee and all other persons who have involvement with the operation and administration of this Plan and this Award shall have no liability to the Holder or any other person for violations of Section 409A of the Code if any provisions relating to the Plan, the Election or this Award are determined to constitute deferred compensation subject to penalties and other related taxes under Section 409A of the Code.

6.    Payment of Award Units. No Common Stock shall be issued at the time this Award is granted, and the Company will not be required to set aside any funds or any property of the Company (or otherwise) for the payment of this Award. The Holder has no voting rights with respect to any Award Units granted under this Award or any other rights of a shareholder of Common Stock of the Company until after a Distribution Event. Pursuant to the Election, the Committee shall deliver Common Stock relating to any and all Vested Units granted under this Award to the Holder as soon as reasonably possible upon the occurrence of a Distribution Event (“Payment Period”), and in no event later than the number of days specified in the Plan with respect to such Distribution Event; provided, however, that if any Payment Period overlaps any two (2) calendar years, the Holder shall be paid as provided in the Plan during the second (2^nd) calendar year after the occurrence of a Distribution Event. After the transfer of any Common Stock on the books and records of the Company upon the occurrence of a Distribution Event, the Holder agrees to hold and retain the required amount of Common Stock as specified in the Company's stock ownership guidelines, as potentially modified from time to time. In the event a beneficiary is entitled to any benefits of the Holder, payment of any Common Stock shall be effectuated as provided in the Election as soon as possible after the death of the Holder.

7.    Dividends. In addition to any Award Units granted under Section 1. above, the Company hereby grants to the Holder an additional number of Award Units equal to the value of dividends granted by the Company on an equivalent number of shares of Common Stock, as if each whole number of vested Award Units were Common Stock (“Dividend Equivalents”); provided, however, that Dividend Equivalents shall be granted by the Company under this Award only: (i) to the extent that actual dividends are declared and paid and/or distributed by the Company in respect to Common Stock; and (ii) with respect to Vested Units. No Dividend Equivalents shall be awarded with respect to Award Units which are not Vested Units at the time the Company actually declares any dividends with respect to any corresponding shares of Common Stock. The Dividend Equivalents shall be credited to the Deferred Stock Unit Account of the Holder at the same time as any such actual dividends are declared and paid and/or distributed in respect to the Common Stock in accordance with the terms of the Plan. Dividend Equivalents shall be subject to the same vesting and corresponding forfeiture requirements as any other Award Units and will be payable at the same time and manner as any other Award Units are paid to the Holder under this Award.

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8.    No Transfers Permitted. The rights under this Award are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Vested Units.

9.    No Right To Continued Board Service.Neither the Plan nor this Award shall confer upon the Holder any right to continue to serve as a Director, nor shall they interfere in any way with Holder's right to resign or otherwise terminate participation on the Board.

10.    Governing Law. Without limitation, this Award shall be construed and enforced in accordance with and governed by the laws of Delaware.

11.    Binding Effect. This Award shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto.

12.    Severability. If any provision of this Award is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Award will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.

13.Committee Authority. The Award shall be administered by the Committee, which shall adopt rules and regulations for carrying out the purposes of the Award and, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to the Administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Award by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.

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IN WITNESS WHEREOF, the Company has caused these presents to be executed on its behalf and its corporate seal to be affixed hereto by its duly authorized representative and the Holder has hereunto set his or her hand and seal, all on the day and year first above written.

	DENBURY RESOURCES INC.
Per:
	Phil Rykhoek, Chief Executive Officer
Per:
	Mark Allen, SVP & Chief Financial Officer

Acknowledgment

The undersigned hereby acknowledges (i) my receipt of this Award, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Award with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Award and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Award and the Plan.

Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or this Award, or both) of the Committee upon any questions arising under the Plan, or this Award, or both.

Dated as of this ________ day of ______________, _______.

______________________________

Holder Signature

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EX-10.E

Exhibit 10(e)

DEFERRED STOCK UNIT AGREEMENT

DENBURY RESOURCES INC.

DIRECTOR DEFERRED COMPENSATION PLAN

(WITH RESPECT TO DEFERRED DIRECTOR FEES)

DEFERRED STOCK UNIT AGREEMENT (“Agreement”) made effective ____________ (“Date of Grant”) between Denbury Resources Inc. (“Company”) and ______________ (“Holder”), a non-employee member of the Board of Directors (“Board”) of the Company.

WHEREAS, the Holder completed a Director Fees Allocation and Deferral Election Form with respect to the directly preceding calendar year (“Election”), pursuant to Section 8(b) of the Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated on December 13, 2012, and as may be further amended (“Plan”), and timely filed such Election with the Company as required under the Plan with respect to the directly preceding calendar year for services rendered as a Board member during the current calendar year;

WHEREAS, consistent with any Election made by the Holder, the Company desires to grant the Holder a certain number of Deferred Stock Units for services rendered by the Holder to the Company as a member of the Board in accordance with the terms of the Plan (“Deferred Stock Units”), as set forth in Section 1 below equal in value to an equivalent number of whole shares of “Common Stock” (as defined below), which Deferred Stock Units shall be paid as specified in this Agreement and the Plan;

WHEREAS, for purposes of this Agreement, “Common Stock” means shares of the common stock of the Company that are registered by the Company under the Plan;

WHEREAS, the Company and Holder understand and agree that the provisions of the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (Amended and Restated as of May 22, 2013), and as may be further amended, shall not apply to this Agreement, except as explicitly provided in the Plan;

WHEREAS, in accordance with the provisions of Section 8(a)(1) of the Plan, the Deferred Stock Units subject to this Agreement will be issued by the Company in the Holder's name and credited to the Holder's Deferred Stock Unit Account under the Plan until such time as a Distribution Event occurs, after which time the Deferred Stock Units shall be payable in Common Stock in accordance with the terms of this Agreement and the Plan;

WHEREAS, the Company and Holder understand and agree that this Agreement is in all respects subject to the terms, definitions and provisions of the Plan and the applicable Election, all of which are incorporated herein by reference, except to the extent otherwise expressly provided in this Agreement; and

WHEREAS, terms capitalized but not defined above (or otherwise) in this Agreement will have the meaning given to such terms under the Plan.

NOW THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the Company and Holder agree as follows:

1.Deferred Stock Units. The Company shall grant to the Holder an aggregate number of Deferred Stock Units, as set forth immediately below, on the terms and conditions set forth in the Plan and as supplemented by the terms of this Agreement, including, without limitation, the vesting provisions set forth in Section 2. below and the distribution provisions set forth in Section 5. below, subject only to Holder's execution of this Agreement. On each Issue Date,

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Director Fees, on the percentage basis set forth in the Election, owed to the Holder for the portion of the Plan Year for which the Director Fees are to be paid shall be converted to Deferred Stock Unitssubstantially equal in value to an equivalent number of whole shares of Common Stock on the Issue Date which would have been applicable to the Director Fees absent the Election. Such Deferred Stock Units shall be credited to the Holder's Deferred Stock Unit Account. As soon as practicable thereafter, a report shall be provided to the Holder setting forth the number of Deferred Stock Units granted to the Holder. The Deferred Stock Units shall be adjusted from time to time as provided in the Plan and this Agreement.

2.Vesting of Deferred Stock Units. The Deferred Stock Units shall fully vest and become non-forfeitable immediately upon being credited to Holder's Deferred Stock Unit Account under the Plan.

3.Withholding and Taxes. There will be no tax withholding with respect to this Agreement. The Agreement is not subject to Section 83 of the Code, relating to certain transfers of property, and Holder agrees and warrants that Holder will not make an election under Section 83(b) with respect to the Agreement.

4.Section 409A of the Code. The Company and Holder intend that this Agreement will be administered in accordance with Section 409A of the Code by the Committee. To the extent that any provision of this Agreement is ambiguous as to its compliance with Section 409A of the Code, the provision shall be read by the Committee in such a manner so that all payments hereunder comply with (or are exempt from, as appropriate) Section 409A of the Code. The Holder agrees that this Agreement may be amended unilaterally by the Company, as may be reasonably requested by either party, and as may be necessary to fully comply with Section 409A of the Code (and all related rules and regulations) in order to preserve the tax treatment to the extent possible of any payments and benefits provided by this Agreement. Notwithstanding the foregoing, the Company makes no representation or warranty, and the Holder acknowledges and agrees that the Company, the Board, the Committee and all other persons who have involvement with the operation and administration of this Plan and this Agreement shall have no liability to the Holder or any other person for violations of Section 409A of the Code if any provisions relating to the Plan, the Election or this Agreement are determined to constitute deferred compensation subject to penalties and other related taxes under Section 409A of the Code.

5.Payment of Deferred Stock Units. No Common Stock shall be issued at the time this Agreement is granted, and the Company will not be required to set aside any funds or any property of the Company (or otherwise) for the payment under this Agreement. The Holder has no voting rights with respect to any Deferred Stock Units granted under this Agreement or any other rights of a shareholder of Common Stock of the Company until after a Distribution Event. Pursuant to the Election, the Committee shall deliver Common Stock relating to any and all Deferred Stock Units granted under this Agreement to the Holder as soon as reasonably possible upon the occurrence of a Distribution Event (“Payment Period”), and in no event later than the number of days specified in the Plan with respect to such Distribution Event; provided, however, that if any Payment Period overlaps any two (2) calendar years, the Holder shall be paid as provided in the Plan during the second (2^nd) calendar year after the occurrence of a Distribution Event. After the transfer of any Common Stock on the books and records of the Company upon the occurrence of a Distribution Event, the Holder agrees to hold and retain the required amount of Common Stock as specified in the Company's stock ownership guidelines, as potentially modified from time to time. In the event a beneficiary is entitled to any benefits of the Holder, payment of any Common Stock shall be effectuated as provided in the Election as soon as possible after the death of the Holder.

6.Dividends. In addition to any Deferred Stock Units granted under Section 1. above, the Company hereby grants to the Holder an additional number of Deferred Stock Units equal to the value of dividends granted by the Company on an equivalent number of shares of Common Stock, as if each whole number of Deferred Stock Units were Common Stock (“Dividend Equivalents”); provided, however, that Dividend Equivalents shall be granted by the Company under this Agreement only to the extent that actual dividends are declared and paid and/or distributed by the Company in respect to Common Stock. The Dividend Equivalents shall be credited to the Deferred Stock Unit

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Account of the Holder at the same time as any such actual dividends are declared and paid and/or distributed in respect to the Common Stock in accordance with the terms of the Plan. Dividend Equivalents will also be fully vested when awarded as additional Deferred Stock Units under this Section 6. Any such Deferred Stock Units attributable to Dividend Equivalents will be payable at the same time and manner as any other Deferred Stock Units are paid to the Holder under this Agreement.

7.No Transfers Permitted. The rights under this Agreement are not transferable by the Holder otherwise than by will or the laws of descent and distribution, and so long as Holder lives, only Holder or his or her guardian or legal representative shall have the right to receive and retain Deferred Stock Units.

8.No Right To Continued Board Service.Neither the Plan nor this Agreement shall confer upon the Holder any right to continue to serve as a director of the Board, nor shall they interfere in any way with Holder's right to resign or otherwise terminate participation on the Board.

9.Governing Law. Without limitation, this Agreement shall be construed and enforced in accordance with and governed by the laws of Delaware.

10.Binding Effect. This Agreement shall inure to the benefit of and be binding upon the heirs, executors, administrators, successors and assigns of the parties hereto.

11.Severability. If any provision of this Agreement is declared or found to be illegal, unenforceable or void, in whole or in part, the remainder of this Agreement will not be affected by such declaration or finding and each such provision not so affected will be enforced to the fullest extent permitted by law.

12.Committee Authority. The Agreement shall be administered by the Committee, which shall adopt rules and regulations for carrying out the purposes of the Agreement and, without limitation, may delegate all of what, in its sole discretion, it determines to be ministerial duties to the Administrator; provided, further, that the determinations under, and the interpretations of, any provision of the Agreement by the Committee shall, in all cases, be in its sole discretion, and shall be final and conclusive.

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IN WITNESS WHEREOF, the Company has caused these presents to be executed on its behalf and its corporate seal to be affixed hereto by its duly authorized representative and the Holder has hereunto set his or her hand and seal, all on the day and year first above written.

	DENBURY RESOURCES INC.
Per:
	Phil Rykhoek, Chief Executive Officer
Per:
	Mark Allen, SVP & Chief Financial Officer

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Acknowledgment

The undersigned hereby acknowledges (i) my receipt of this Agreement, (ii) my opportunity to review the Plan, (iii) my opportunity to discuss this Agreement with a representative of the Company, and my personal advisors, to the extent I deem necessary or appropriate, (iv) my understanding of the terms and provisions of the Agreement and the Plan, and (v) my understanding that, by my signature below, I am agreeing to be bound by all of the terms and provisions of this Agreement and the Plan.

Without limitation, I agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or this Agreement, or both) of the Committee upon any questions arising under the Plan, or this Agreement, or both.

Dated as of this ________ day of ______________, _____.

______________________________

Holder Signature

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EX-31.A

Exhibit 31(a)

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Phil Rykhoek, certify that:

1. I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 6, 2013	/s/ Phil Rykhoek
	Phil Rykhoek
	President and Chief Executive Officer

EX-31.B

Exhibit 31(b)

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark C. Allen, certify that:

1. I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 6, 2013	/s/ Mark Allen
	Mark C. Allen
	Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

EX-32

Exhibit 32

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying Annual Report on Form 10-Q for the quarter ended June 30, 2013 (the Report) of Denbury Resources Inc. (Denbury) as filed with the Securities and Exchange Commission, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.

Dated:	August 6, 2013	/s/ Phil Rykhoek
		Phil Rykhoek
		President and Chief Executive Officer
Dated:	August 6, 2013	/s/ Mark C. Allen
		Mark C. Allen
		Senior Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

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Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2013

Basis of Presentation (Tables) [Abstract]

Weighted average shares used in the basic and diluted net income per common share

The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:

	Three Months Ended June 30,		Six Months Ended June 30,
In thousands	2013	2012	2013	2012
Basic weighted average common shares outstanding	368,850	387,159	369,122	386,764
Potentially dilutive securities:
Restricted stock, stock options, SARs and performance-based equity awards	3,119	3,543	3,295	4,059
Diluted weighted average common shares outstanding	371,969	390,702	372,417	390,823

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Condensed Consolidated Statements of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues and other income
Oil, natural gas, and related product sales	$ 638,188	$ 592,141	$ 1,211,841	$ 1,225,642
CO2 sales and transportation fees	6,562	5,301	13,120	12,096
Interest income and other income	5,334	4,339	8,209	9,159
Total revenues and other income	650,084	601,781	1,233,170	1,246,897
Expenses
Lease operating expenses	220,558	124,511	361,100	262,475
Marketing expenses	13,332	12,218	23,128	23,048
CO2 discovery and operating expenses	3,419	1,062	7,141	7,267
Taxes other than income	44,940	38,812	82,951	82,506
General and administrative	33,382	34,826	75,271	71,433
Interest, net of amounts capitalized of $23,279, $18,475, $44,984, and $37,920, respectively	30,602	41,604	66,636	77,918
Depletion, depreciation, and amortization	126,907	132,289	239,805	253,184
Derivatives expense (income)	(45,501)	(139,109)	(33,572)	(93,834)
Loss on early extinguishment of debt	428	0	44,651	0
Impairment of assets	0	215	0	17,515
Other expenses	10,711	12,552	12,818	23,272
Total expenses	438,778	258,980	879,929	724,784
Income before income taxes	211,306	342,801	353,241	522,113
Income tax provision	81,326	130,936	135,690	196,781
Net income	$ 129,980	$ 211,865	$ 217,551	$ 325,332
Net income per common share - basic	$ 0.35	$ 0.55	$ 0.59	$ 0.84
Net income per common share - diluted	$ 0.35	$ 0.54	$ 0.58	$ 0.83
Weighted average common shares outstanding
Basic	368,850	387,159	369,122	386,764
Diluted	371,969	390,702	372,417	390,823

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 2. Acquisitions and Divestitures

Fair Value. 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 do not impact the measurement of fair value unless those assumptions are consistent with market participant views.

The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions may include: (1) NYMEX oil and natural gas futures (this input is observable); (2) dollar-per-acre values of recent sale transactions (this input is observable); (3) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible; (4) estimated oil and natural gas pricing differentials; (5) projections of future rates of production; (6) timing and amount of future development and operating costs; (7) projected costs of CO₂ (to a market participant); (8) projected reserve recovery factors; and (9) risk-adjusted discount rates.

2013 Acquisition

Cedar Creek Anticline Acquisition. In January 2013, we entered into an agreement to acquire producing assets in the Cedar Creek Anticline ("CCA") of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips Company ("ConocoPhillips") for $1.05 billion. On March 27, 2013, we closed the acquisition for $989.0 million in cash after closing adjustments, primarily for revenues and costs of the purchased properties from the January 1, 2013 effective date to the closing date. We funded the acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction (described below) from which $1.05 billion was placed in qualifying trust accounts in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. The $1.05 billion placed in qualifying trust accounts was classified as Restricted Cash in our December 31, 2012 Consolidated Balance Sheet. This acquisition meets the definition of a business under the FASC Business Combinations topic. As such, we estimated the fair value of assets acquired and liabilities assumed as of March 27, 2013, the closing date of the acquisition, using a discounted future net cash flow model. The current purchase price allocation is preliminary, pending further evaluation of the oil and natural gas properties, other assets and related asset retirement obligations.

The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed in the CCA acquisition:

In thousands
Consideration:
Cash payment (1)	$	988,982
Fair value of assets acquired and liabilities assumed:
Oil and natural gas properties
Proved	771,487
Unevaluated	222,820
Other assets	1,884
Asset retirement obligations	(7,209		)
	$	988,982

(1) This cash payment was made through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

For the three months ended June 30, 2013 and for the period from March 27, 2013 to June 30, 2013, we recognized $88.7 million and $92.7 million of oil, natural gas, and related product sales, respectively, from the property interests acquired in the CCA acquisition. For the three months ended June 30, 2013 and for the period from March 27, 2013 to June 30, 2013, we recognized $65.2 million and $67.9 million of net field operating income (oil, natural gas and related product sales less lease operating expenses and production and ad valorem taxes and marketing expenses), respectively, related to the CCA acquisition.

2012 Acquisitions and Divestitures

Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction (the "Bakken Exchange Transaction") with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”) in which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash (after closing adjustments), (2) ExxonMobil's operating interests in Webster Field in Texas and Hartzog Draw Field in Wyoming, and (3) approximately a one-third overriding royalty ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field in Wyoming. No material adjustments were made during the first six months of 2013 to the preliminary fair value of the assets acquired and liabilities assumed previously disclosed in our Form 10-K.

Thompson Field Acquisition. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after closing adjustments. The field is located in close proximity to Hastings Field, which is an enhanced oil recovery field that we are currently flooding with CO₂ and which is the current terminus of the Green Pipeline which transports CO₂ both from the Jackson Dome area, located near Jackson, Mississippi, and from various anthropogenic sources. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also a planned future tertiary field. Under the terms of the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO₂ injection.

This acquisition meets the definition of a business under the FASC Business Combinations topic. The fair values assigned to assets acquired and liabilities assumed in the June 2012 acquisition have been finalized and no adjustments have been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2012.

Unaudited Pro Forma Acquisition Information. The following combined pro forma total revenues and other income and net income are presented as if the CCA Acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per share data	2013		2012		2013		2012
Pro forma total revenues and other income	$	650,084	$	640,996	$	1,315,344	$	1,327,045
Pro forma net income	129,980		234,621		245,571		368,152
Pro forma net income per common share
Basic	$	0.35	$	0.61	$	0.67	$	0.95
Diluted	0.35		0.60		0.66		0.94

Other 2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million. The sale had an effective date of January 1, 2012 and proceeds received after consideration of final closing adjustments totaled $68.5 million. In February 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for net proceeds of $141.8 million, after final closing adjustments. The sale had an effective date of December 1, 2011. We did not record a gain or loss on these divestitures in accordance with the full cost method of accounting.

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Acquisitions and Divestitures (CCA PPA) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Mar. 27, 2013
Business Acquisition [Line Items]
Cash payment		$ 988,982	[1]
Other assets	1,884
Asset retirement obligations	(7,209)
Business Acquisition, Purchase Price Allocation, Assets Acquired Less (Liabilities Assumed)	988,982
Proved Properties [Member]
Business Acquisition [Line Items]
Oil and natural gas properties	771,487
Unevaluated Properties [Member]
Business Acquisition [Line Items]
Oil and natural gas properties	$ 222,820

[1] This cash payment was made through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2013

Acquisitions and Divestitures (Tables) [Abstract]

Schedule of Business Acquisitions, CCA

The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed in the CCA acquisition:

In thousands
Consideration:
Cash payment (1)	$	988,982
Fair value of assets acquired and liabilities assumed:
Oil and natural gas properties
Proved	771,487
Unevaluated	222,820
Other assets	1,884
Asset retirement obligations	(7,209		)
	$	988,982

(1) This cash payment was made through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

Business Acquisition, Pro Forma Information

Unaudited Pro Forma Acquisition Information. The following combined pro forma total revenues and other income and net income are presented as if the CCA Acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per share data	2013		2012		2013		2012
Pro forma total revenues and other income	$	650,084	$	640,996	$	1,315,344	$	1,327,045
Pro forma net income	129,980		234,621		245,571		368,152
Pro forma net income per common share
Basic	$	0.35	$	0.61	$	0.67	$	0.95
Diluted	0.35		0.60		0.66		0.94

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Long-Term Debt (Components of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Bank Credit Agreement	$ 260,000	$ 700,000
Pipeline financings	231,626	236,244
Capital lease obligations	141,332	158,260
Total	3,233,059	3,141,428
Less current obligations	(34,148)	(36,966)
Long-term debt and capital lease obligations	3,198,911	3,104,462
9.5% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	0	234,038
Including premium of	0	9,118
Debt Instrument, Interest Rate, Stated Percentage	9.50%
9.75% Senior Subordinated Notes due 2016 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	0	412,781
Including discount of	0	13,569
Debt Instrument, Interest Rate, Stated Percentage	9.75%
8.25% Senior Subordinated Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	996,273	996,273
Debt Instrument, Interest Rate, Stated Percentage	8.25%
6 3/8% Senior Subordinated Notes Due 2021 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	400,000	400,000
Debt Instrument, Interest Rate, Stated Percentage	6.375%
4 5/8% Senior Subordinated Notes Due 2023 [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	1,200,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.625%
Other Subordinated Notes [Member]
Debt Instrument [Line Items]
Senior Subordinated Notes	3,828	3,832
Including premium of	$ 21	$ 25

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Acquisitions and Divestitures (Details Textuals) (USD $)	6 Months Ended					1 Months Ended		6 Months Ended	1 Months Ended	6 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Mar. 27, 2013		Dec. 31, 2012	Jun. 30, 2012 Thompson Field [Member] Rate	Feb. 29, 2012 Non-core Gulf Coast Assets [Member]	Jun. 30, 2012 Non-core Gulf Coast Assets [Member]	Apr. 30, 2012 Paradox Basin [Member]	Jun. 30, 2012 Paradox Basin [Member]	Dec. 31, 2012 Bakken Exchange Transaction [Member] Rate	Jan. 31, 2013 Cedar Creek Anticline [Member]	Jun. 30, 2013 Cedar Creek Anticline [Member]	Jun. 30, 2013 Cedar Creek Anticline [Member]
Acquisitions and Divestitures (Textuals) [Abstract]
Anticipated purchase price of oil and natural gas properties												$ 1,050,000,000
Business Acquisition, Cost of Acquired Entity, Cash Paid			988,982,000	[1]		366,200,000
Proceeds from Delayed Tax Exempt Exchange											1,050,000,000
Restricted cash	0				1,050,015,000
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual													88,700,000	92,700,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual													65,200,000	67,900,000
Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents											1,300,000,000
Overriding Royalty Interest Obtained In A Business Acquisition											33.33%
Net working interest acquired in purchase of oil and natural gas properties						100.00%
Net revenue interest acquired in purchase of oil and natural gas properties						84.70%
Net Revenue Interest Retained By Seller						5.00%
Oil Production Threshold (in Bbls/d)						3,000
Anticipated Proceeds From Sale Of Oil And Natural Gas Properties									75,000,000
Proceeds from Sale of Oil and Gas Property and Equipment	5,496,000	32,302,000					141,800,000		68,500,000
Gain (Loss) on Sale of Property								$ 0		$ 0

[1] This cash payment was made through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

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Fair Value Measurements (Details Textuals) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Components Of Impairment Nonoperating [Line Items]
Sensitivity Analysis of Fair Value, Impact of 1 Percent Increase or Decrease in Level 3 Inputs	$ 300,000		$ 300,000
Other Asset Impairment Charges	0	215,000	0	17,515,000
Long-term Debt, Fair Value	2,855,000,000		2,855,000,000		2,957,000,000
Faustina Investment Impairment [Member]
Components Of Impairment Nonoperating [Line Items]
Other Asset Impairment Charges				$ 15,100,000

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Derivative Instruments and Hedging Activities (Commodity Derivatives Outstanding) (Details)	Jun. 30, 2013
Year 2013 [Member] | Q3 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	56,000
Floor price	79.64
Ceiling price	109.15
Year 2013 [Member] | Q3 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	75.00
Year 2013 [Member] | Q3 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	133.10
Year 2013 [Member] | Q4 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	54,000
Floor price	80.00
Ceiling price	117.53
Year 2013 [Member] | Q4 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2013 [Member] | Q4 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	127.50
Year 2014 [Member] | Q1 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	58,000
Floor price	80.00
Ceiling price	102.11
Year 2014 [Member] | Q1 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2014 [Member] | Q1 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	104.50
Year 2014 [Member] | Q2 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	58,000
Floor price	80.00
Ceiling price	102.11
Year 2014 [Member] | Q2 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2014 [Member] | Q2 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	104.50
Year 2014 [Member] | Q3 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	58,000
Floor price	80.00
Ceiling price	97.73
Year 2014 [Member] | Q3 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2014 [Member] | Q3 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	100.00
Year 2014 [Member] | Q4 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	58,000
Floor price	80.00
Ceiling price	97.73
Year 2014 [Member] | Q4 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2014 [Member] | Q4 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	100.00
Year 2015 [Member] | Q1 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	38,000
Floor price	80.00
Ceiling price	96.96
Year 2015 [Member] | Q1 [Member] | LLS [Member]
Derivative [Line Items]
Volume per Day	20,000
Floor price	85.00
Ceiling price	101.45
Year 2015 [Member] | Q1 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2015 [Member] | Q1 [Member] | Minimum [Member] | LLS [Member]
Derivative [Line Items]
Derivative Price Range	85.00
Year 2015 [Member] | Q1 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	100.90
Year 2015 [Member] | Q1 [Member] | Maximum [Member] | LLS [Member]
Derivative [Line Items]
Derivative Price Range	104.00
Year 2015 [Member] | Q2 [Member] | NYMEX [Member]
Derivative [Line Items]
Volume per Day	24,000
Floor price	80.00
Ceiling price	94.40
Year 2015 [Member] | Q2 [Member] | LLS [Member]
Derivative [Line Items]
Volume per Day	20,000
Floor price	85.00
Ceiling price	102.01
Year 2015 [Member] | Q2 [Member] | Minimum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	80.00
Year 2015 [Member] | Q2 [Member] | Minimum [Member] | LLS [Member]
Derivative [Line Items]
Derivative Price Range	85.00
Year 2015 [Member] | Q2 [Member] | Maximum [Member] | NYMEX [Member]
Derivative [Line Items]
Derivative Price Range	95.25
Year 2015 [Member] | Q2 [Member] | Maximum [Member] | LLS [Member]
Derivative [Line Items]
Derivative Price Range	103.00

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Acquisitions and Divestitures Acquisitions and Divestitures (Pro Forma) (Details 1) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Business Acquisition [Line Items]
Pro forma total revenues and other income	$ 650,084	$ 640,996	$ 1,315,344	$ 1,327,045
Pro forma net income	$ 129,980	$ 234,621	$ 245,571	$ 368,152
Pro forma net income per common share [Abstract]
Basic	$ 0.35	$ 0.61	$ 0.67	$ 0.95
Diluted	$ 0.35	$ 0.60	$ 0.66	$ 0.94

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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Statement of Other Comprehensive Income [Abstract]
Net income	$ 129,980	$ 211,865	$ 217,551	$ 325,332
Other comprehensive income, net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $10, $19 and $21, respectively	17	17	37	35
Total other comprehensive income	17	17	37	35
Comprehensive income	$ 129,997	$ 211,882	$ 217,588	$ 325,367

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Cash flow from operating activities:
Net income	$ 217,551	$ 325,332
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation, and amortization	239,805	253,184
Deferred income taxes	128,342	167,289
Stock-based compensation	15,671	15,249
Noncash fair value derivative adjustments	(33,516)	(87,686)
Loss on early extinguishment of debt	44,651	0
Amortization of debt issuance costs and discounts	7,139	7,347
Impairment of assets	0	17,515
Other, net	5,041	15,835
Changes in assets and liabilities, net of effects from acquisitions:
Accrued production receivable	(6,769)	35,466
Trade and other receivables	3,117	(10,769)
Other current and long-term assets	(9,171)	6,851
Accounts payable and accrued liabilities	86,969	28,256
Oil and natural gas production payable	20,222	(7,985)
Other liabilities	(12,308)	(33,264)
Net cash provided by operating activities	706,744	732,620
Cash flow used in investing activities:
Oil and natural gas capital expenditures	(486,163)	(574,008)
Acquisitions of oil and natural gas properties	(307)	(154,366)
CO2 capital expenditures	(44,708)	(53,313)
Pipelines and plants capital expenditures	(97,480)	(169,675)
Purchases of other assets	(22,825)	(10,748)
Net proceeds from sales of oil and natural gas properties and equipment	5,496	32,302
Proceeds from sale of short-term investments	0	83,545
Other	(19,586)	(2,961)
Net cash used in investing activities	(665,573)	(849,224)
Cash flow provided by (used in) financing activities:
Bank repayments	(970,000)	(400,000)
Bank borrowings	530,000	535,000
Repayment of senior subordinated notes	(651,270)	0
Premium paid on repayment of senior subordinated notes	(36,475)	0
Proceeds from issuance of senior subordinated notes	1,200,000	0
Costs of debt financing	(20,026)	(11)
Common stock repurchase program	(100,423)	0
Other	(15,623)	(8,965)
Net cash provided by (used in) financing activities	(63,817)	126,024
Net increase (decrease) in cash and cash equivalents	(22,646)	9,420
Cash and cash equivalents at beginning of period	98,511	18,693
Cash and cash equivalents at end of period	$ 75,865	$ 28,113

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Long-Term Debt

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Long-Term Debt

Note 3. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:

	June 30,			December 31,
In thousands	2013			2012
Bank Credit Agreement	$	260,000		$	700,000
9½% Senior Subordinated Notes due 2016, including premium of $9,118	—			234,038
9¾% Senior Subordinated Notes due 2016, including discount of $13,569	—			412,781
8¼% Senior Subordinated Notes due 2020	996,273			996,273
6 3/8% Senior Subordinated Notes due 2021	400,000			400,000
4 5/8% Senior Subordinated Notes due 2023	1,200,000			—
Other Subordinated Notes, including premium of $21 and $25, respectively	3,828			3,832
Pipeline financings	231,626			236,244
Capital lease obligations	141,332			158,260
Total	3,233,059			3,141,428
Less: current obligations	(34,148		)	(36,966		)
Long-term debt and capital lease obligations	$	3,198,911		$	3,104,462

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

4 5/8% Senior Subordinated Notes due 2023

In February 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the “2023 Notes”). The 2023 Notes, which carry a coupon rate of 4.625%, were sold at par. The net proceeds, after issuance costs, of approximately $1.18 billion were used to repurchase or redeem a portion of our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes"), all of our 9¾% Senior Subordinated Notes due 2016 (the "9¾% Notes") (see Repurchase and Redemption of 9½% Notes and 9¾% Notes below) and to pay down a portion of outstanding borrowings on our Bank Credit Facility (as defined below).

The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year, commencing July 15, 2013. We may redeem the 2023 Notes in whole or in part at our option beginning January 15, 2018, at the following redemption prices: 102.313%on or after January 15, 2018; 101.542%on or after January 15, 2019; 100.771%on or after January 15, 2020; and 100%on or after January 15, 2021. Prior to January 15, 2016, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2023 Notes at a redemption price of 104.625% with the proceeds of certain equity offerings. In addition, at any time prior to January 15, 2018, we may redeem 100% of the principal amount of the 2023 Notes at a redemption price equal to 100% of the principal amount plus a “make whole” premium and accrued and unpaid interest. The indenture for the 2023 Notes (the "2023 Indenture") contains certain restrictions on our ability to take or permit certain actions, including restrictions on our ability to: (1) incur additional debt; (2) pay dividends on our common stock or redeem, repurchase or retire such stock or subordinated debt unless certain leverage ratios are met; (3) make investments; (4) create liens on our assets; (5) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (6) engage in transactions with our affiliates; (7) transfer or sell assets; and (8) consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. Although the covenants contained in our other senior subordinated notes indentures are generally consistent with those contained in our 2023 Indenture, the 2023 Indenture covenants permit us in certain circumstances to make restricted payments exceeding the amount allowed under our other senior subordinated notes indentures.  Under the 2023 Indenture, these restricted payments, which include share repurchases and dividend payments, do not reduce our restricted payment limitation, provided we maintain (both before and after giving effect to any such payment) a predefined leverage ratio of at least 2.5 to 1. The leverage ratio represents the ratio of total debt to EBITDA, both as defined within the 2023 Indenture.

Repurchase and Redemption of 9½% Notes and 9¾% Notes

On January 22, 2013, we commenced cash tender offers to purchase the outstanding $426.4 million principal amount of our 9¾% Notes at 105.425% of par and the outstanding $224.9 million principal amount of our 9½% Notes at 106.869% of par. During February 2013, we accepted for purchase $191.7 million principal amount of the outstanding 9¾% Notes and $186.7 million principal amount of the outstanding 9½% Notes. We received sufficient consents in the solicitation to amend the indenture governing the 9½% Notes to eliminate most of the restrictive covenants and certain events of default. The purchases under these tender offers were funded by a portion of the proceeds received from the issuance of our 2023 Notes. The tender offers expired on February 19, 2013.

On February 5, 2013, we issued a notice of redemption for the remaining $234.7 million principal amount outstanding of our 9¾% Notes at 104.875% of par, and on March 7, 2013, we repurchased all of the remaining 9¾% Notes outstanding. On March 28, 2013, we issued a notice of redemption for the remaining $38.2 million principal amount outstanding of our 9½% Notes at 104.75% of par, and on May 1, 2013, we repurchased all of the remaining 9½% Notes outstanding.

We recognized a loss associated with the debt repurchases of $0.4 million and $44.7 million during the three and six months endedJune 30, 2013, respectively, consisting of both premium payments made to repurchase or redeem the 9¾% Notes and 9½% Notes and the elimination of unamortized debt issuance costs, discounts and premiums related to these notes. The loss is included in our Unaudited Condensed Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt".

$1.6 Billion Revolving Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the "Bank Credit Agreement").  Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations.  The borrowing base is adjusted at the banks' discretion and is based in part upon external factors over which we have no control.  If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period not to exceed four months. As part of the semi-annual review completed on May 1, 2013 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion. Our next semi-annual redetermination is scheduled to occur on or around November 1, 2013.  The weighted average interest rate on borrowings under this revolving credit facility, evidenced by the Bank Credit Agreement (the "Bank Credit Facility") was 1.7% as of June 30, 2013.  We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base.  Loans under the Bank Credit Facility mature in May 2016.

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Basis of Presentation

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

Note 1. Basis of Presentation

Organization and Nature of Operations

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2012 (the "Form 10-K").  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of June 30, 2013, our consolidated results of operations for the three and six months endedJune 30, 2013 and 2012, and our consolidated cash flows for the six months ended June 30, 2013 and 2012.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.

Net Income per Common Share

Basic net income per common share is computed by dividing net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance-based equity awards.  For the three and six months endedJune 30, 2013 and 2012, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.

The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:

	Three Months Ended June 30,		Six Months Ended June 30,
In thousands	2013	2012	2013	2012
Basic weighted average common shares outstanding	368,850	387,159	369,122	386,764
Potentially dilutive securities:
Restricted stock, stock options, SARs and performance-based equity awards	3,119	3,543	3,295	4,059
Diluted weighted average common shares outstanding	371,969	390,702	372,417	390,823

Basic weighted average common shares excludes shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. Stock options and SARs of 3.7 million shares for the three and six months ended June 30, 2013, respectively, and 3.9 million and 3.5 million shares for the three and six months ended June 30, 2012, respectively, were not included in the computation of diluted net income per share as their effect would have been antidilutive.

Recent Accounting Pronouncements

Balance Sheet Offsetting. In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the Financial Accounting Standards Board Codification ("FASC"), including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 became effective for our fiscal year beginning January 1, 2013 and have been applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 did not affect our consolidated financial statements, but required additional disclosures in the notes thereto.

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Long-Term Debt (Details Textuals) (USD $)	3 Months Ended		6 Months Ended		1 Months Ended	6 Months Ended		1 Months Ended	0 Months Ended		0 Months Ended	1 Months Ended		6 Months Ended			6 Months Ended
	Jun. 30, 2013 Rate	Jun. 30, 2012	Jun. 30, 2013 Rate	Jun. 30, 2012	Feb. 28, 2013 4 5/8% Senior Subordinated Notes Due 2023 [Member]	Jun. 30, 2013 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate	Dec. 31, 2012 4 5/8% Senior Subordinated Notes Due 2023 [Member]	Mar. 07, 2013 9.75% Senior Subordinated Notes due 2016 [Member] Rate	Feb. 19, 2013 9.75% Senior Subordinated Notes due 2016 [Member] Rate	Jan. 22, 2013 9.75% Senior Subordinated Notes due 2016 [Member]	Feb. 19, 2013 9.5% Senior Subordinated Notes due 2016 [Member] Rate	May 01, 2013 9.5% Senior Subordinated Notes due 2016 [Member] Rate	Jan. 22, 2013 9.5% Senior Subordinated Notes due 2016 [Member]	Jun. 30, 2013 Bank Credit Agreement [Member] Rate	May 01, 2013 Bank Credit Agreement [Member]	Mar. 31, 2010 Bank Credit Agreement [Member]	Jun. 30, 2013 Bank Credit Agreement [Member] Minimum [Member] Rate	Jun. 30, 2013 Bank Credit Agreement [Member] Maximum [Member] Rate	Jun. 30, 2013 Debt Instrument, Redemption, Period One [Member] 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate	Jun. 30, 2013 Debt Instrument, Redemption, Period Two [Member] 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate	Jun. 30, 2013 Debt Instrument, Redemption, Period Three [Member] 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate	Jun. 30, 2013 Debt Instrument, Redemption, Period Four [Member] 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate	Jun. 30, 2013 Initial Redemption Period with Proceeds from Equity Offering [Member] 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate	Jun. 30, 2013 Initial Redemption Period with Make-Whole Premium [Member] 4 5/8% Senior Subordinated Notes Due 2023 [Member] Rate
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries	100.00%		100.00%
Face Value of Notes Issued					$ 1,200,000,000
Debt Instrument, Maturity Date						Jul. 15, 2023
Debt Instrument, Interest Rate, Stated Percentage						4.625%
Selling Price Of Debt Instrument					100.00%
Proceeds from issuance of subordinated long term debt, net of commissions and fees						1,180,000,000
Debt Instrument, Redemption Period, Start Date																			on or after January 15, 2018	on or after January 15, 2019	on or after January 15, 2020	on or after January 15, 2021	Prior to January 15, 2016	prior to January 15, 2018
Debt Instrument, Redemption Price, Percentage								104.875%	105.425%		106.869%	104.75%							102.313%	101.542%	100.771%	100.00%	104.625%	100.00%
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed																							35.00%	100.00%
Leverage Ratio Requirement for Restricted Payments						at least 2.5 to 1
Subordinated Debt						1,200,000,000	0			426,400,000			224,900,000
Debt Instrument, Repurchased Face Amount								234,700,000	191,700,000		186,700,000	38,200,000
Loss on early extinguishment of debt	428,000	0	44,651,000	0
$1.6 Billion Revolving Credit Facility [Abstract]
Borrowing Base of Denbury credit facility															$ 1,600,000,000	$ 1,600,000,000
Weighted average interest rate on Bank Credit Facility														1.70%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage																	0.375%	0.50%

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Derivative Instruments and Hedging Activities (Derivatives By Balance Sheet Location) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative assets - current	$ 9,915	$ 19,477
Derivative assets - long-term	18,712	36
Derivative liabilities - current	(1,895)	(2,842)
Derivative liabilities - long-term	(87)	(23,781)
Total derivatives not designated as hedging instruments	26,645	(7,110)
Crude Oil Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative assets - current	9,915	19,477
Derivative assets - long-term	18,712	36
Derivative liabilities - current	(1,895)	(2,659)
Derivative liabilities - long-term	(87)	(23,781)
Deferred Premiums [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities - current	$ 0	$ (183)

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Stockholders' equity
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	408,547,073	406,163,194
Treasury stock, shares	35,642,949	30,601,262

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Fair Value Measurements

6 Months Ended

Jun. 30, 2013

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]

Fair Value Measurements

Note 6. Fair Value Measurements

The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

• Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. We currently have 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. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

• Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2013, instruments in this category include non-exchange-traded oil collars that are based on regional pricing other than NYMEX (i.e., Louisiana Light Sweet). Our costless collars are valued using the Black-Scholes model, which is described above. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. A one percent increase or decrease in implied volatility would result in a change of approximately $0.3 million in the fair value of these instruments as of June 30, 2013.

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

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:

	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
June 30, 2013
Assets:
Oil derivative contracts	$	—	$	25,444		$	3,183		$	28,627
Liabilities:
Oil derivative contracts	—		(1,895		)	(87		)	(1,982		)
Total	$	—	$	23,549		$	3,096		$	26,645
December 31, 2012
Assets:
Oil derivative contracts	$	—	$	19,513		$	—		$	19,513
Liabilities:
Oil derivative contracts	—		(26,440		)	—			(26,440		)
Total	$	—	$	(6,927	)	$	—		$	(6,927	)

Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

During the first quarter of 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of Faustina Hydrogen Products LLC, which impairment was classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statement of Operations for the six months ended June 30, 2012.  The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset.  These inputs are unobservable within the marketplace and therefore considered Level 3 within the fair value hierarchy.  However, as there are currently no expected future cash flows associated with the plant, the preferred stock was determined to have no value.

Other Fair Value Measurements

The carrying value of our Bank Credit Facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine fair value of our fixed-rate debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our total long-term debt as of June 30, 2013 and December 31, 2012, excluding pipeline financing and capital lease obligations, was $2.855 billion and $2.957 billion, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Expenses
Capitalized interest	$ 23,279	$ 18,475	$ 44,984	$ 37,920

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Condensed Consolidated Balance Sheets (Unaudited) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 75,865	$ 98,511
Restricted cash	0	1,050,015
Accrued production receivable	256,572	253,131
Trade and other receivables, net	94,814	81,971
Derivative assets	9,915	19,477
Deferred tax assets	30,392	29,156
Other current assets	16,500	10,493
Total current assets	484,058	1,542,754
Oil and natural gas properties (using full cost accounting)
Proved	8,144,381	6,963,211
Unevaluated	1,126,585	809,154
CO2 properties	1,068,890	1,032,653
Pipelines and plants	2,115,243	2,035,126
Other property and equipment	424,919	417,207
Less accumulated depletion, depreciation, amortization, and impairment	(3,406,131)	(3,180,241)
Net property and equipment	9,473,887	8,077,110
Derivative assets	18,712	36
Goodwill	1,283,590	1,283,590
Other assets	248,263	235,852
Total assets	11,508,510	11,139,342
Current liabilities
Accounts payable and accrued liabilities	395,652	414,668
Oil and gas production payable	182,657	161,945
Derivative liabilities	1,895	2,842
Current maturities of long-term debt	34,148	36,966
Total current liabilities	614,352	616,421
Long-term liabilities
Long-term debt, net of current portion	3,198,911	3,104,462
Asset retirement obligations	115,049	102,730
Derivative liabilities	87	23,781
Deferred taxes	2,283,028	2,153,452
Other liabilities	26,297	23,607
Total long-term liabilities	5,623,372	5,408,032
Commitments and contingencies (Note 7)
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	0	0
Common stock, $.001 par value, 600,000,000 shares authorized; 408,547,073 and 406,163,194 shares issued, respectively	409	406
Paid-in capital in excess of par	3,161,193	3,136,461
Retained earnings	2,652,386	2,434,835
Accumulated other comprehensive loss	(311)	(348)
Treasury stock, at cost, 35,642,949 and 30,601,262 shares, respectively	(542,891)	(456,465)
Total stockholders' equity	5,270,786	5,114,889
Total liabilities and stockholders' equity	$ 11,508,510	$ 11,139,342

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Share Repurchase Program (Details Textuals) (USD $) In Millions, except Per Share data, unless otherwise specified	1 Months Ended	3 Months Ended	6 Months Ended	21 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2013
Stockholders' Equity Note [Abstract]
Treasury Stock, Shares, Acquired		1.1	5.0	36.1
Treasury Stock, Value, Acquired, Cost Method		$ 19.0	$ 85.2	$ 547.1
Treasury Stock Acquired, Average Cost Per Share				$ 15.15
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$ 224.1

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Basis of Presentation (Details Textuals) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Basis of Presentation (Textuals) [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	3.7	3.9	3.7	3.5

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Commitments and Contingencies Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	7 Months Ended
	Jun. 30, 2013	Jul. 31, 2013
Loss Contingencies [Line Items]
Environmental Remediation Expense	$ 70.0	$ 45.0
Maximum [Member]
Loss Contingencies [Line Items]
Estimated Percentage of Environmental Remediation Expense Estimate to be Recovered Through Insurance Proceeds	67.00%
Minimum [Member]
Loss Contingencies [Line Items]
Estimated Percentage of Environmental Remediation Expense Estimate to be Recovered Through Insurance Proceeds	33.00%

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2013

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 5. Derivative Instruments

Oil and Natural Gas Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production approximately two years in the future from the current 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 and commodity price volatility. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands	2013			2012			2013			2012
Oil
Cash payment on settlements of derivative contracts	$	—		$	709		$	—		$	8,939
Noncash fair value adjustments to derivative contracts – income	(45,501		)	(140,923		)	(33,572		)	(98,478		)
Total derivatives income – oil	(45,501		)	(140,214		)	(33,572		)	(89,539		)
Natural Gas
Cash receipt on settlements of derivative contracts	—			(7,991		)	—			(15,031		)
Noncash fair value adjustments to derivative contracts – expense	—			9,096			—			10,736
Total derivatives expense (income) – natural gas	—			1,105			—			(4,295		)
Derivatives expense (income)	$	(45,501	)	$	(139,109	)	$	(33,572	)	$	(93,834	)

Commodity Derivative Contracts Not Classified as Hedging Instruments

The following table presents outstanding oil derivative contracts with respect to future production as of June 30, 2013:

					Contract Prices per Barrel of Oil
		Type of	Pricing	Volume					Weighted Average Price
Year	Months	Contract	Index	(Barrels per day)	Range				Floor		Ceiling
2013	July – Sept	Collar	NYMEX	56,000	$	75.00	–	133.10	$	79.64	$	109.15
	Oct – Dec	Collar	NYMEX	54,000		80.00	–	127.50	80.00		117.53
2014	Jan – Mar	Collar	NYMEX	58,000	$	80.00	–	104.50	$	80.00	$	102.11
	Apr – June	Collar	NYMEX	58,000		80.00	–	104.50	80.00		102.11
	July – Sept	Collar	NYMEX	58,000		80.00	–	100.00	80.00		97.73
	Oct – Dec	Collar	NYMEX	58,000		80.00	–	100.00	80.00		97.73
2015	Jan – Mar	Collar	NYMEX	38,000	$	80.00	–	100.90	$	80.00	$	96.96
	Jan – Mar	Collar	LLS	20,000		85.00	–	104.00	85.00		101.45
	Apr – June	Collar	NYMEX	24,000		80.00	–	95.25	80.00		94.40
	Apr – June	Collar	LLS	20,000		85.00	–	103.00	85.00		102.01

Additional Disclosures about Derivative Instruments

At June 30, 2013 and December 31, 2012, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

		Estimated Fair Value Asset (Liability)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2013			2012
		In thousands
Derivative assets
Crude oil contracts	Derivative assets – current	$	9,915		$	19,477
Crude oil contracts	Derivative assets – long-term	18,712			36
Derivative liabilities
Crude oil contracts	Derivative liabilities – current	(1,895		)	(2,659		)
Deferred premiums	Derivative liabilities – current	—			(183		)
Crude oil contracts	Derivative liabilities – long-term	(87		)	(23,781		)
Total derivatives not designated as hedging instruments		$	26,645		$	(7,110	)

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, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement. As of June 30, 2013 all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

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Derivative Instruments and Hedging Activities (Summary of Derivative Income/Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Derivative Instruments, Loss (Gain) [Line Items]
Total derivatives expense (income) - oil & natural gas	$ (45,501)	$ (139,109)	$ (33,572)	$ (93,834)
Derivatives expense (income)	(45,501)	(139,109)	(33,572)	(93,834)
Crude Oil Contracts [Member]
Derivative Instruments, Loss (Gain) [Line Items]
Cash payment (receipt) on settlements of derivative contracts	0	709	0	8,939
Noncash fair value adjustments to derivative contracts - expense (income)	(45,501)	(140,923)	(33,572)	(98,478)
Total derivatives expense (income) - oil & natural gas	(45,501)	(140,214)	(33,572)	(89,539)
Natural Gas Contracts [Member]
Derivative Instruments, Loss (Gain) [Line Items]
Cash payment (receipt) on settlements of derivative contracts	0	(7,991)	0	(15,031)
Noncash fair value adjustments to derivative contracts - expense (income)	0	9,096	0	10,736
Total derivatives expense (income) - oil & natural gas	$ 0	$ 1,105	$ 0	$ (4,295)

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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Organization and Nature of Operations

Organization and Nature of Operations

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

Interim Financial Statements - Basis of Accounting

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2012 (the "Form 10-K").  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Interim Financial Statements - Use of Estimates

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of June 30, 2013, our consolidated results of operations for the three and six months endedJune 30, 2013 and 2012, and our consolidated cash flows for the six months ended June 30, 2013 and 2012.

Reclassifications

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.

Net Income Per Common Share

Net Income per Common Share

Basic net income per common share is computed by dividing net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance-based equity awards.  For the three and six months endedJune 30, 2013 and 2012, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.

The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:

	Three Months Ended June 30,		Six Months Ended June 30,
In thousands	2013	2012	2013	2012
Basic weighted average common shares outstanding	368,850	387,159	369,122	386,764
Potentially dilutive securities:
Restricted stock, stock options, SARs and performance-based equity awards	3,119	3,543	3,295	4,059
Diluted weighted average common shares outstanding	371,969	390,702	372,417	390,823

Basic weighted average common shares excludes shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. Stock options and SARs of 3.7 million shares for the three and six months ended June 30, 2013, respectively, and 3.9 million and 3.5 million shares for the three and six months ended June 30, 2012, respectively, were not included in the computation of diluted net income per share as their effect would have been antidilutive.

New Accounting Pronouncements

Recent Accounting Pronouncements

Balance Sheet Offsetting. In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the Financial Accounting Standards Board Codification ("FASC"), including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 became effective for our fiscal year beginning January 1, 2013 and have been applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 did not affect our consolidated financial statements, but required additional disclosures in the notes thereto.

Derivatives

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production approximately two years in the future from the current 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 and commodity price volatility. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program.

It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

Fair Value of Financial Instruments

The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

• Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. We currently have 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. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

• Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2013, instruments in this category include non-exchange-traded oil collars that are based on regional pricing other than NYMEX (i.e., Louisiana Light Sweet). Our costless collars are valued using the Black-Scholes model, which is described above. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. A one percent increase or decrease in implied volatility would result in a change of approximately $0.3 million in the fair value of these instruments as of June 30, 2013.

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

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Share Repurchase Program

6 Months Ended

Jun. 30, 2013

Stockholders' Equity Note [Abstract]

Share Repurchase Program

Note 4. Share Repurchase Program

Under our board-authorized share repurchase program, we repurchased 1.1 million shares of Denbury common stock for $19.0 million during the three months ended June 30, 2013 and 5.0 million shares of Denbury common stock for $85.2 million during the six months ended June 30, 2013. Since commencement of the share repurchase program in October 2011 through June 30, 2013, we have repurchased a total of 36.1 million shares of Denbury common stock for $547.1 million, or $15.15 per share. As of June 30, 2013, we had $224.1 million of remaining repurchases authorized under our share repurchase program.

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Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Other comprehensive income, net of income tax:
Tax for interest rate lock derivative contracts reclassified to income	$ 11	$ 10	$ 19	$ 21

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Fair Value Measurements (Fair Value Heirarchy Table) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Assets, Fair Value Disclosure [Abstract]
Oil derivative contracts	$ 28,627	$ 19,513
Liabilities, Fair Value Disclosure [Abstract]
Oil derivative contracts	(1,982)	(26,440)
Total	26,645	(6,927)
Quoted Prices in Active Markets (Level 1) [Member]
Assets, Fair Value Disclosure [Abstract]
Oil derivative contracts	0	0
Liabilities, Fair Value Disclosure [Abstract]
Oil derivative contracts	0	0
Total	0	0
Significant Other Observable Inputs (Level 2) [Member]
Assets, Fair Value Disclosure [Abstract]
Oil derivative contracts	25,444	19,513
Liabilities, Fair Value Disclosure [Abstract]
Oil derivative contracts	(1,895)	(26,440)
Total	23,549	(6,927)
Significant Unobservable Inputs (Level 3) [Member]
Assets, Fair Value Disclosure [Abstract]
Oil derivative contracts	3,183	0
Liabilities, Fair Value Disclosure [Abstract]
Oil derivative contracts	(87)	0
Total	$ 3,096	$ 0

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Components of Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of the dates indicated:

	June 30,			December 31,
In thousands	2013			2012
Bank Credit Agreement	$	260,000		$	700,000
9½% Senior Subordinated Notes due 2016, including premium of $9,118	—			234,038
9¾% Senior Subordinated Notes due 2016, including discount of $13,569	—			412,781
8¼% Senior Subordinated Notes due 2020	996,273			996,273
6 3/8% Senior Subordinated Notes due 2021	400,000			400,000
4 5/8% Senior Subordinated Notes due 2023	1,200,000			—
Other Subordinated Notes, including premium of $21 and $25, respectively	3,828			3,832
Pipeline financings	231,626			236,244
Capital lease obligations	141,332			158,260
Total	3,233,059			3,141,428
Less: current obligations	(34,148		)	(36,966		)
Long-term debt and capital lease obligations	$	3,198,911		$	3,104,462

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 7. Commitments and Contingencies

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

Delhi Field Release

In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and a small percentage of oil, was discovered and reported within the Denbury-operated Delhi Field located in northern Louisiana.  Denbury immediately took remedial action to stop the release and contain and recover well fluids in the affected area. We continue to actively work with government and local officials and agencies to determine the best course of remediation. Currently, we believe the origin of the release to be one or more wells in the affected area of the field that had been previously plugged and abandoned. We currently estimate that we will incur a minimum of $70.0 million to stop the release and remediate the affected area. Accordingly, during the second quarter of 2013, we recorded $70.0 million of lease operating expense related to the release in our Unaudited Condensed Consolidated Statement of Operations and a corresponding liability classified as Accounts payable and accrued liabilities in our Unaudited Condensed Consolidated Balance Sheet. This estimate is based on costs incurred through July 31, 2013 of approximately $45.0 million, plus the Company's estimate of the minimum level of future costs based on our current understanding of the environmental impact of the release and methods available to remediate impacted properties. Since the area is still in the process of being remediated and final restoration plans have not yet been agreed upon with regulatory agencies, we are currently unable to reliably estimate the full extent of the costs that may ultimately be incurred by the Company related to this release. The Company maintains insurance coverage which we believe covers certain of the costs and damages related to the release, and we currently estimate that one-third to two-thirds of our minimum cost estimate may be recoverable under our insurance policies. However, we have not reached any agreement with our insurance carriers as to recoverable amounts, and given the uncertainties concerning our ultimate insurance recoveries, we have not recognized any such recoveries in our financial statements as of June 30, 2013. Insurance recoveries will be recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.

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Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Weighted average shares used in the basic and diluted net income per common share
Weighted average common shares - basic	368,850	387,159	369,122	386,764
Potentially dilutive securities:
Restricted stock, stock options, SARs, and performance-based equity awards	3,119	3,543	3,295	4,059
Weighted average common shares - diluted	371,969	390,702	372,417	390,823

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities (Tables) [Abstract]

Commodity derivative expense (income) included in our Unaudited Condensed Consolidated Statements of Operations

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands	2013			2012			2013			2012
Oil
Cash payment on settlements of derivative contracts	$	—		$	709		$	—		$	8,939
Noncash fair value adjustments to derivative contracts – income	(45,501		)	(140,923		)	(33,572		)	(98,478		)
Total derivatives income – oil	(45,501		)	(140,214		)	(33,572		)	(89,539		)
Natural Gas
Cash receipt on settlements of derivative contracts	—			(7,991		)	—			(15,031		)
Noncash fair value adjustments to derivative contracts – expense	—			9,096			—			10,736
Total derivatives expense (income) – natural gas	—			1,105			—			(4,295		)
Derivatives expense (income)	$	(45,501	)	$	(139,109	)	$	(33,572	)	$	(93,834	)

Commodity derivative contracts not classified as hedging instruments

The following table presents outstanding oil derivative contracts with respect to future production as of June 30, 2013:

					Contract Prices per Barrel of Oil
		Type of	Pricing	Volume					Weighted Average Price
Year	Months	Contract	Index	(Barrels per day)	Range				Floor		Ceiling
2013	July – Sept	Collar	NYMEX	56,000	$	75.00	–	133.10	$	79.64	$	109.15
	Oct – Dec	Collar	NYMEX	54,000		80.00	–	127.50	80.00		117.53
2014	Jan – Mar	Collar	NYMEX	58,000	$	80.00	–	104.50	$	80.00	$	102.11
	Apr – June	Collar	NYMEX	58,000		80.00	–	104.50	80.00		102.11
	July – Sept	Collar	NYMEX	58,000		80.00	–	100.00	80.00		97.73
	Oct – Dec	Collar	NYMEX	58,000		80.00	–	100.00	80.00		97.73
2015	Jan – Mar	Collar	NYMEX	38,000	$	80.00	–	100.90	$	80.00	$	96.96
	Jan – Mar	Collar	LLS	20,000		85.00	–	104.00	85.00		101.45
	Apr – June	Collar	NYMEX	24,000		80.00	–	95.25	80.00		94.40
	Apr – June	Collar	LLS	20,000		85.00	–	103.00	85.00		102.01

Derivative financial instruments included in our Unaudited Condensed Consolidated Balance Sheet

At June 30, 2013 and December 31, 2012, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:

		Estimated Fair Value Asset (Liability)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2013			2012
		In thousands
Derivative assets
Crude oil contracts	Derivative assets – current	$	9,915		$	19,477
Crude oil contracts	Derivative assets – long-term	18,712			36
Derivative liabilities
Crude oil contracts	Derivative liabilities – current	(1,895		)	(2,659		)
Deferred premiums	Derivative liabilities – current	—			(183		)
Crude oil contracts	Derivative liabilities – long-term	(87		)	(23,781		)
Total derivatives not designated as hedging instruments		$	26,645		$	(7,110	)

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Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Jul. 31, 2013
Document And Company Information [Abstract]
Entity Registrant Name	Denbury Resources Inc.
Entity Central Index Key	0000945764
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		372,912,110

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]

Fair value hierarchy of financial assets and liabilities

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:

	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
June 30, 2013
Assets:
Oil derivative contracts	$	—	$	25,444		$	3,183		$	28,627
Liabilities:
Oil derivative contracts	—		(1,895		)	(87		)	(1,982		)
Total	$	—	$	23,549		$	3,096		$	26,645
December 31, 2012
Assets:
Oil derivative contracts	$	—	$	19,513		$	—		$	19,513
Liabilities:
Oil derivative contracts	—		(26,440		)	—			(26,440		)
Total	$	—	$	(6,927	)	$	—		$	(6,927	)