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, 2008

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

Commission file number 1-12935

DENBURY RESOURCES INC.

Delaware (State or other jurisdictions of incorporation or organization)		20-0467835 (I.R.S. Employer Identification No.)
5100 Tennyson Parkway Suite 1200
Plano, TX (Address of principal executive offices)		75024 (Zip code)

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

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 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):

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).
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, 2008
Common Stock, $.001 par value		246,910,322

 

 

INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at June 30, 2008 and December 31, 2007			3
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2008 and 2007			4
Unaudited Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2008 and 2007			5
Unaudited Condensed Consolidated Statements of Comprehensive Operations for the Three and Six Months Ended June 30, 2008 and 2007			6
Notes to Unaudited Condensed Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 3. Quantitative and Qualitative Disclosures about Market Risk			34
Item 4. Controls and Procedures			34
Part II. Other Information
Item 1. Legal Proceedings			34
Item 1A. Risk Factors			34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			35
Item 3. Defaults Upon Senior Securities			35
Item 4. Submission of Matters to a Vote of Security Holders			35
Item 5. Other Information			35
Item 6. Exhibits			36
Signatures			37
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)

		June 30,				December 31,
		2008				2007
Assets
Current assets
Cash and cash equivalents		$	147,009			$	60,107
Accrued production receivable			180,644				136,284
Trade and other receivables, net of allowance of $393 and $369			72,222				28,977
Deferred tax assets			45,083				12,708
Derivative assets			—				2,283
Total current assets			444,958				240,359
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved			3,022,567				2,682,932
Unevaluated			275,338				366,518
CO2 properties and equipment			545,497				436,591
Other			62,532				50,116
Less accumulated depletion and depreciation			(1,247,141	)			(1,143,282	)
Net property and equipment			2,658,793				2,392,875
Deposits on property under option or contract			49,162				49,097
Other assets			120,201				88,746
Total assets		$	3,273,114			$	2,771,077
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities		$	126,613			$	147,580
Oil and gas production payable			111,215				84,150
Derivative liabilities			92,286				28,096
Deferred revenue — Genesis			4,070				4,070
Current maturities of long-term debt			3,838				737
Total current liabilities			338,022				264,633
Long-term liabilities
Long-term debt — Genesis			251,582				4,544
Long-term debt			525,596				675,786
Asset retirement obligations			42,230				38,954
Deferred revenue — Genesis			22,242				24,424
Deferred tax liability			457,502				347,370
Other			11,272				10,988
Total long-term liabilities			1,310,424				1,102,066
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; 247,401,427 and 245,386,951 shares issued at June 30, 2008 and December 31, 2007, respectively			247				245
Paid-in capital in excess of par			693,935				662,698
Retained earnings			938,234				751,179
Accumulated other comprehensive loss			(661	)			(1,591	)
Treasury stock, at cost, 550,635 and 637,795 shares at June 30, 2008 and December 31, 2007, respectively			(7,087	)			(8,153	)
Total stockholders’ equity			1,624,668				1,404,378
Total liabilities and stockholders’ equity		$	3,273,114			$	2,771,077

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Revenues and other income
Oil, natural gas and related product sales		$	413,243			$	217,479			$	726,440			$	386,613
CO2 sales and transportation fees			3,383				3,394				6,234				6,485
Interest income and other			1,359				1,637				2,646				3,567
Total revenues			417,985				222,510				735,320				396,665
Expenses
Lease operating expenses			76,825				57,207				142,826				107,764
Production taxes and marketing expenses			18,688				9,035				33,874				17,863
Transportation expense — Genesis			1,842				1,351				3,392				2,727
CO2 operating expenses			453				1,204				1,596				1,907
General and administrative			14,811				11,694				30,816				23,128
Interest, net of amounts capitalized of $5,545, $4,321, $12,811, and $8,354, respectively			8,141				8,356				13,082				14,431
Depletion, depreciation and amortization			54,733				46,235				104,572				87,262
Commodity derivative expense (income)			58,817				(15,049	)			105,598				11,858
Total expenses			234,310				120,033				435,756				266,940
Income before income taxes			183,675				102,477				299,564				129,725
Income tax provision
Current income taxes			10,844				7,343				32,080				8,961
Deferred income taxes			58,778				32,567				80,429				41,581
Net income		$	114,053			$	62,567			$	187,055			$	79,183
Net income per common share — basic		$	0.47			$	0.26			$	0.77			$	0.33
Net income per common share — diluted		$	0.45			$	0.25			$	0.74			$	0.32
Weighted average common shares outstanding
Basic			243,623				239,586				243,189				238,789
Diluted			252,401				249,537				252,603				249,459

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Cash flow from operating activities:
Net income		$	114,053			$	62,567			$	187,055			$	79,183
Adjustments needed to reconcile to net cash flow provided by operations:
Depletion, depreciation and amortization			54,733				46,235				104,572				87,262
Deferred income taxes			58,778				32,567				80,429				41,581
Deferred revenue — Genesis			(1,138	)			(1,066	)			(2,182	)			(2,022	)
Stock based compensation			3,499				2,664				7,385				5,450
Non-cash fair value derivative adjustments			29,875				(13,437	)			69,003				21,721
Amortization of debt issue costs and other			(677	)			963				(396	)			1,545
Changes in assets and liabilities related to operations:
Accrued production receivable			(38,325	)			(23,550	)			(44,359	)			(22,070	)
Trade and other receivables			(38,520	)			(2,806	)			(46,879	)			(11,785	)
Other assets			1,107				(124	)			269				(146	)
Accounts payable and accrued liabilities			(26,928	)			(10,515	)			(10,442	)			(15,501	)
Oil and gas production payable			9,431				7,782				27,065				9,211
Other liabilities			(1,816	)			972				(1,191	)			1,168
Net cash provided by operating activites			164,072				102,252				370,329				195,597
Cash flow used for investing activities:
Oil and natural gas capital expenditures			(142,701	)			(160,290	)			(299,003	)			(299,309	)
Acquisitions of oil and gas properties			(1,955	)			(7,523	)			(2,357	)			(46,660	)
Change in accrual for capital expenditures			3,610				(4,514	)			(5,999	)			(8,769	)
Distributions from Genesis			1,475				—				2,725				—
Acquisitions of CO2 assets and CO2 capital expenditures			(66,324	)			(37,011	)			(108,850	)			(68,427	)
Net purchases of other assets			(6,652	)			(1,837	)			(16,931	)			(2,734	)
Net proceeds from sales of oil and gas properties and equipment			(5,196	)			5,835				49,029				5,840
Other			(641	)			(64	)			(686	)			(960	)
Net cash used for investing activities			(218,384	)			(205,404	)			(382,072	)			(421,019	)
Cash flow from financing activities:
Bank repayments			(131,000	)			(140,000	)			(222,000	)			(140,000	)
Bank borrowings			20,000				80,000				72,000				176,000
Payments on capital lease obligations			(182	)			(166	)			(360	)			(327	)
Income tax benefit from equity awards			8,729				6,280				14,143				8,840
Pipeline financing — Genesis			225,248				—				225,248				—
Issuance of subordinated debt			—				150,750				—				150,750
Issuance of common stock			4,556				5,477				9,710				10,687
Other			(69	)			(1,619	)			(96	)			(1,824	)
Net cash provided by financing activities			127,282				100,722				98,645				204,126
Net increase (decrease) in cash and cash equivalents			72,970				(2,430	)			86,902				(21,296	)
Cash and cash equivalents at beginning of period			74,039				35,007				60,107				53,873
Cash and cash equivalents at end of period		$	147,009			$	32,577			$	147,009			$	32,577
Supplemental disclosure of cash flow information:
Cash paid during the period for interest		$	20,947			$	18,970			$	22,997			$	21,349
Cash paid during the period for income taxes			55,999				6,332				58,629				7,370
Interest capitalized			5,545				4,321				12,811				8,354

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE OPERATIONS
(In thousands)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Net income		$	114,053			$	62,567			$	187,055			$	79,183
Other comprehensive income, net of income tax:
Change in fair value of derivative contracts designated as a hedge, net of tax of $301, $364, $49 and $36, respectively			492				570				12				57
Interest rate lock derivative contracts reclassified to income, net of taxes of $551 and $562, respectively			900				—				918				—
Comprehensive income		$	115,445			$	63,137			$	187,985			$	79,240

(See accompanying Notes to Unaudited Condensed Consolidated Financial Statements)

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Interim Financial Statements

     The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Denbury” or “Company” refer to Denbury Resources Inc. and its subsidiaries. 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, 2007. Any capitalized terms used but not defined in these Notes to Unaudited Condensed Consolidated Financial Statements have the same meaning given to them in the Form 10-K.

     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 fiscal year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments (of a normal recurring nature) necessary to present fairly the consolidated financial position of Denbury as of June 30, 2008 and the consolidated results of its operations and cash flows for the three and six month periods ended June 30, 2008 and 2007. Certain prior period items have been reclassified to make the classification consistent with the classification in the most recent quarter.

Stock Split

     On November 19, 2007, stockholders of Denbury Resources Inc. approved an amendment to our Restated Certificate of Incorporation to increase the number of shares of our authorized common stock from 250,000,000 shares to 600,000,000 shares and to split our common stock on a 2-for-1 basis. Stockholders of record on December 5, 2007, received one additional share of Denbury common stock for each share of common stock held at that time. Information pertaining to shares and earnings per share has been retroactively adjusted in the accompanying financial statements and related notes thereto to reflect the stock split.

Net Income Per Common Share

     Basic net income per common share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact on net income and common shares for the potential dilution from stock options, stock appreciation rights (“SARs”), non-vested restricted stock and any other convertible securities outstanding. For the three and six month periods ended June 30, 2008 and 2007, there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three and six month periods ended June 30, 2008 and 2007.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
Shares in Thousands		2008				2007				2008				2007
Weighted average common shares — basic			243,623				239,586				243,189				238,789
Potentially dilutive securities:
Stock options and SARs			7,389				8,520				8,043				9,315
Restricted stock			1,389				1,431				1,371				1,355
Weighted average common shares — diluted			252,401				249,537				252,603				249,459

     The weighted average common shares — basic amount excludes 2,668,538 shares at June 30, 2008 and 3,062,282 shares at June 30, 2007, of non-vested restricted stock that is subject to future vesting over time. 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 weighted

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

average common shares — diluted, the non-vested restricted stock is included in the computation using the treasury stock method, with the proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. The dilution impact of these shares on our earnings per share calculation may increase in future periods, depending on the market price of our common stock during those periods.

     For the three months ended June 30, 2008 and 2007, stock options to purchase approximately 49,000 and 159,000 shares of common stock, and for the six months ended June 30, 2008 and 2007, stock options to purchase approximately 691,000 and 314,000 shares of common stock, respectively, were outstanding but excluded from the diluted net income per common share calculations, as the exercise prices of the options exceeded the average market price of the Company’s common stock during these periods and would be anti-dilutive to the calculations.

Accounting for Tertiary Injection Costs

     Prior to January 1, 2008, we expensed all costs associated with injecting CO₂ used in our tertiary recovery operations, even though some of these costs were incurred prior to any tertiary related oil production. Commencing January 1, 2008, we began capitalizing, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO₂ injections (i.e. a production response). These capitalized development costs are included in our unevaluated property costs until we record proved tertiary reserves in that field associated with those costs. After we see a production response to the CO₂ injections (i.e. the production stage), injection costs are expensed as incurred, and any previously deferred development costs included in unevaluated properties become subject to depletion upon recognition of proved tertiary reserves. Since we are continuing to initiate new tertiary floods, this means that we are now capitalizing certain costs that we historically expensed. Had we continued with the prior accounting methodology of expensing all tertiary injectant costs, we would have expensed an additional $2.9 million during the first quarter of 2008 and $1.4 million during the second quarter of 2008. During the first half of 2007, the impact of this accounting methodology was not material, as only $0.6 million would have been capitalized under the new accounting procedure.

Recently Adopted Accounting Pronouncement

Fair Value Measurements

     During the first quarter of 2008, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with United States generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. On February 12, 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. This deferral of SFAS No. 157 applies to our asset retirement obligation (“ARO”), which uses fair value measures at the date incurred to determine our liability. However, we do not expect the adoption of SFAS No. 157 to significantly change the methodology we use to estimate the initial fair value of our ARO, because the guidance in SFAS No. 157 is consistent with the fair value guidance in SFAS No. 143, “Accounting for Asset Retirement Obligations” which we apply to determine our ARO.

     As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. 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 minimizes the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 defined by SFAS No. 157 are as follows:

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     Level 1 — Quoted prices in active markets for identical assets or liabilities as of the reporting date. During 2008 we had no level 1 recurring measurements.

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

     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. During 2008 we had no level 3 recurring measurements.

     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 June 30, 2008.

Fair Value Measurements at June 30, 2008 Using

Significant

Quoted Prices

Other

Significant

in Active

Observable

Unobservable

Markets

Inputs

Inputs

Amounts in thousands

(Level 1)

(Level 2)

(Level 3)

Total

Liabilities:

Oil and natural gas derivative contracts

$

—

$

92,286

$

—

$

92,286

Recently Issued Accounting Pronouncement

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of SFAS No. 133.” SFAS No. 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS No. 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS No. 133 have been applied, and the impact that hedges have on an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for us beginning January 1, 2009. We have not yet determined what impact, if any, this pronouncement will have on our disclosures about derivatives.

Note 2. Oil and Gas Properties Divestiture

Sale of Louisiana Natural Gas Assets

     In October 2007, we entered into an agreement to sell our Louisiana natural gas assets to a privately held company for approximately $180 million (before closing adjustments), plus we retained a net profits interest in one well. In late December 2007, we closed on approximately 70% of that sale with net proceeds of approximately $108.6 million (including estimated final purchase price adjustments). We closed on the remaining portion of the sale in February 2008 and received net proceeds of approximately $48.9 million. The agreement has an effective date of August 1, 2007, and consequently operating net revenue after August 1, 2007, net of capital expenditures, along with any other minor closing items were adjustments to the purchase price. The potential net profits interest relates to a well in the South Chauvin field and is only earned if operating income from that well exceeds certain levels, which we believe could potentially increase the ultimate value we receive by up to 10%. The operating results of these sold properties are included in our financial statements through the applicable closing dates of the sold properties. We did not record any gain or loss on the sale in accordance with the full cost method of accounting.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Asset Retirement Obligations

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

     The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2008.

		Six Months Ended
Amounts in thousands		June 30, 2008
Balance, beginning of period		$	41,258
Liabilities incurred and assumed during period			894
Revisions in estimated retirement obligations			1,072
Liabilities settled during period			(750	)
Accretion expense			1,524
Sales			(63	)
Balance, end of period		$	43,935

     At June 30, 2008, $1.7 million of our asset retirement obligation was classified in “Accounts payable and accrued liabilities” under current liabilities in our Unaudited Condensed Consolidated Balance Sheets. Liabilities incurred during the six month period ended June 30, 2008 are primarily for oil and natural gas wells drilled during the period. We hold cash and liquid investments in escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $9.6 million at June 30, 2008 and $9.5 million at December 31, 2007 and are included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets.

Note 4. Long-term Debt

		June 30,				December 31,
Amounts in thousands		2008				2007
7.5% Senior Subordinated Notes due 2015		$	300,000			$	300,000
Premium on Senior Subordinated Notes due 2015			642				685
7.5% Senior Subordinated Notes due 2013			225,000				225,000
Discount on Senior Subordinated Notes due 2013			(923	)			(1,020	)
NEJD Financing — Genesis			175,000				—
Free State Financing — Genesis			75,248				—
Senior bank loan			—				150,000
Capital lease obligations — Genesis			4,900				5,238
Capital lease obligations			1,149				1,164
Total			781,016				681,067
Less current obligations			3,838				737
Long-term debt and capital lease obligations		$	777,178			$	680,330

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

NEJD Financing and Free State Financing

     On May 30, 2008, we closed on two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines. The two transactions have been recorded as financing leases. See “Note 5. Related Party Transactions — Genesis — NEJD Pipeline and Free State Pipeline Transactions.”

Senior Bank Loan

     Effective April 1, 2008, we amended our Sixth Amended and Restated Credit Agreement, the instrument governing our senior bank loan, which increased our borrowing base from $500 million to $1.0 billion. With regard to our bank credit facility, the borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($350 million), up to the borrowing base limit ($1.0 billion), although the banks are not obligated to fund any amount in excess of the commitment amount.

5. Related Party Transactions — Genesis

Interest in and Transactions with Genesis

     Denbury’s subsidiary, Genesis Energy, Inc. is the general partner of, and together with Denbury’s other subsidiaries, owns an aggregate 12% interest in, Genesis, a publicly traded master limited partnership. Genesis’ business is focused on the mid stream segment of the oil and gas industry in the Gulf Coast area of the United States, and its activities include gathering, marketing and transportation of crude oil and natural gas, refinery services, wholesale marketing of CO₂, and supply and logistic services.

     We account for our 12% ownership in Genesis under the equity method of accounting as we have significant influence over the limited partnership; however, our control is limited under the limited partnership agreement and therefore we do not consolidate Genesis. Our investment in Genesis is included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets. Denbury received cash distributions from Genesis of $2.8 million and $0.6 million during the six months ended June 30, 2008 and 2007, respectively. We also received $0.1 million in each of these periods as directors’ fees for certain officers of Denbury that are board members of Genesis. There are no guarantees by Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis Energy, Inc.

NEJD Pipeline and Free State Pipeline Transactions

     On May 30, 2008, we closed on two transactions with Genesis involving our Northeast Jackson Dome (NEJD) pipeline system and Free State CO₂ pipeline, which included a long-term transportation service agreement for the Free State pipeline and a 20-year financing lease for the NEJD system. We received from Genesis $225 million in cash and $25 million in Genesis common limited partnership units. We used the proceeds to repay our outstanding borrowing on our bank credit facility and the balance we have temporarily invested in cash. We have recorded both of these transactions as financing leases. At June 30, 2008, we have $175 million for the NEJD financing and $75.2 million for the Free State financing recorded as debt on our balance sheet (see “Note 4. Long-term Debt”).

     The NEJD pipeline system is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldsonville, Louisiana, and is currently being used by us to transport CO₂ for our tertiary operations in southwest Mississippi. We have the rights to exclusive use of the NEJD pipeline system, we will be responsible for all operations and maintenance on the system, and we will bear and assume all obligations and liabilities with respect to the pipeline. The NEJD financing lease requires us to make quarterly base rent payments beginning August 30, 2008. These quarterly rent payments are fixed at $5.2 million per quarter or approximately $20.7 million per year (prorated for 2008) during the 20-year term, at an interest rate of approximately 10.25% per annum. At the end of the term, Genesis will release its secured interest in the line to us for $1.00. We have the option or obligation upon the occurrence of certain events specified in the financing lease, and may have the obligation if we default, to prepay our financing lease obligations. In the event of significant downgrades of our corporate credit rating by the rating agencies, Genesis can require certain credit enhancements from us, and possibly other remedies under the lease.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     The Free State pipeline is an 86-mile, 20” pipeline that extends from our CO₂ source fields at the Jackson Dome, near Jackson, Mississippi, to our oil fields in east Mississippi. Under the terms of the transportation agreement, Genesis is responsible for owning, operating, maintaining and making improvements to the pipeline. We have exclusive use of the pipeline and are required to use the pipeline to supply CO₂ to certain of our tertiary operations in east Mississippi. The Free State transportation agreement requires us to make monthly payments of $100,000 plus a through-put fee based on average daily volumes per month with no minimum volumes required. Based on our forecasted through-put, we currently project that we will initially pay Genesis approximately $9.3 million per annum (prorated for 2008). Approximately $1.5 million (increasing at 1% per year) of the annual payments will be expensed as operating costs, with the remainder recognized as principal and interest expense. The implicit rate on the financing is approximately 13.2% per annum.

Oil Sales and Transportation Services

     We utilize Genesis’ trucking services and common carrier pipelines to transport certain of our crude oil production to sales points where it is sold to third party purchasers. In the first six months of 2008 and 2007, we expensed $3.4 million and $2.7 million, respectively, for these transportation services.

Transportation Leases

     In late 2004 and early 2005, we entered into pipeline transportation agreements with Genesis to transport our crude oil from certain of our fields in Southwest Mississippi, and to transport CO₂ from our main CO₂ pipeline to Brookhaven Field for our tertiary operations. We have accounted for these agreements as capital leases. The pipelines held under these capital leases are classified as property and equipment and are amortized using the straight-line method over the lease terms. Lease amortization is included in depreciation expense. The related obligations are recorded as debt. At June 30, 2008 and December 31, 2007, we had $4.9 million and $5.2 million, respectively, of capital lease obligations with Genesis recorded as liabilities in our Unaudited Condensed Consolidated Balance Sheets.

CO₂ Volumetric Production Payments

     During 2003 through 2005, we sold 280.5 Bcf of CO₂ to Genesis under three separate volumetric production payment agreements. We have recorded the net proceeds of these volumetric production payment sales as deferred revenue and recognize such revenue as CO₂ is delivered under the volumetric production payments. At June 30, 2008 and December 31, 2007, $26.3 million and $28.5 million, respectively, was recorded as deferred revenue, of which $4.1 million was included in current liabilities at both June 30, 2008 and December 31, 2007. We recognized deferred revenue of $1.1 million for each of the three months ended June 30, 2008 and 2007, and $2.2 million and $2.0 million during the six month periods ended June 30, 2008 and 2007, respectively, for deliveries under these volumetric production payments. We provide Genesis with certain processing and transportation services in connection with transporting CO₂ to their industrial customers for a fee of approximately $0.18 per Mcf of CO₂. For these services, we recognized revenues of $1.4 million and $1.2 million for the three month periods ended June 30, 2008 and 2007, respectively, and $2.6 million and $2.3 million for the six months ended June 30, 2008 and 2007, respectively.

Note 6. Derivative Instruments and Hedging Activities

Oil and Gas Derivative Contracts

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

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

     The following is a summary of “Commodity derivative income (expense)” included in our Unaudited Condensed Consolidated Statements of Operations:

		Three Months								Six Months
Amounts in thousands		Ended June 30,								Ended June 30,
		2008				2007				2008				2007
Receipt (payment) on settlements of derivative contracts — Oil		$	(12,131	)		$	(1,108	)		$	(19,523	)		$	(981	)
Receipt (payment) of settlements of derivative contracts — Gas			(16,463	)			2,827				(17,119	)			10,951
Fair value adjustments to derivative contracts — income (expense)			(30,223	)			13,330				(68,956	)			(21,828	)
Commodity derivative income (expense)		$	(58,817	)		$	15,049			$	(105,598	)		$	(11,858	)

Estimated

Fair Value Liability

NYMEX Contract Prices Per Bbl

at June 30, 2008

Type of Contract and Period

Bbls/d

Swap Price

(In Thousands)

Swap Contracts

July 2008 — Dec. 2008

2,000

$

57.34

$

(30,533

)

     Natural Gas Contracts at June 30, 2008:

										Estimated
										Fair Value Liability
		NYMEX Contract Prices Per MMBtu								at June 30, 2008
Type of Contract and Period		MMBtu/d				Swap Price				(In Thousands)
Swap Contracts
July 2008 — Dec. 2008			20,000			$	7.89			$	(20,670	)
July 2008 — Dec. 2008			20,000				7.91				(20,596	)
July 2008 — Dec. 2008			20,000				7.94				(20,487	)

     At June 30, 2008, our oil and natural gas derivative contracts were recorded at their fair value, which was a net liability of $92.3 million.

Interest Rate Lock Derivative Contracts

     In January 2007, we entered into interest rate lock contracts to remove our exposure to possible interest rate fluctuations related to our commitment to the sale-leaseback financing of certain equipment for CO₂ recycling facilities at our tertiary oil fields. We are applying hedge accounting to these contracts as provided under SFAS No. 133. For these instruments designated as interest rate hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Amounts representing hedge ineffectiveness are recorded in earnings. Hedge effectiveness is assessed quarterly based on the total change in the contract’s fair value.

     On June 30, 2008, we settled our remaining interest rate lock contracts for a payment due to the counterparty of approximately $1.6 million (payment made to the counterparty in July 2008 in this amount). During the second quarter of 2008, we determined that we would not complete the anticipated sale-leaseback transactions which were designated as the forecasted hedged transactions for several of the interest rate lock contracts. As a result, we reclassified the $1.4 million in fair market value changes for these contracts that was in Accumulated Other Comprehensive Loss to expense during the second quarter of 2008. We have $0.7 million (net of taxes of $0.4 million) in Accumulated Other Comprehensive Loss in our June 30, 2008 Unaudited Condensed Consolidating Balance Sheet. We recognized ineffectiveness totaling $0.1 million as expense in our Unaudited Condensed Consolidating Statement of Operations for the six months ended June 30, 2008.

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 7. Income Taxes

     The Company recently obtained approval from the Internal Revenue Service (“IRS”) to change its method of tax accounting for certain assets used in its tertiary oilfield recovery operations. Previously, the Company capitalized and depreciated these costs, but now it can deduct these costs once the assets are placed into service. As a result, the Company expects to receive tax refunds of approximately $6 million for tax years through 2007, and in the second quarter of 2008 has reduced its current income tax expense by approximately $19 million to adjust for the impact of this change through the first six months of 2008. The reduction in current income tax expense has been offset by a corresponding increase in deferred income tax expense of approximately the same amount. Although this change is not expected to have a significant impact on the Company’s overall tax rate, it is anticipated that it will reduce the amount of cash taxes the Company expects to pay over the next several years.

Note 8. Condensed Consolidating Financial Information

     Our subordinated debt is fully and unconditionally guaranteed jointly and severally by all of Denbury Resources Inc.’s subsidiaries other than minor subsidiaries, except that with respect to our $225 million of 7.5% Senior Subordinated Notes due 2013, Denbury Resources Inc. and Denbury Onshore, LLC are co-obligors. Except as noted in the foregoing sentence, Denbury Resources Inc. is the sole issuer and Denbury Onshore, LLC is a subsidiary guarantor. The results of our equity interest in Genesis are reflected through the equity method by one of our subsidiaries, Denbury Gathering & Marketing. Each subsidiary guarantor and the subsidiary co-obligor are 100% owned, directly or indirectly, by Denbury Resources Inc. The following is condensed consolidating financial information for Denbury Resources Inc., Denbury Onshore, LLC, and subsidiary guarantors:

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Balance Sheets

		June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Assets
Current assets		$	469,622			$	449,986			$	17,249			$	(491,899	)		$	444,958
Property and equipment			—				2,654,355				4,438				—				2,658,793
Investment in subsidiaries (equity method)			1,150,194				—				1,094,464				(2,244,658	)			—
Other assets			317,837				111,365				55,612				(315,451	)			169,363
Total assets		$	1,937,653			$	3,215,706			$	1,171,763			$	(3,052,008	)		$	3,273,114
Liabilities and Stockholders’ Equity
Current liabilities		$	12,342			$	796,042			$	21,537			$	(491,899	)		$	338,022
Long-term liabilities			300,643				1,325,200				32				(315,451	)			1,310,424
Stockholders’ equity			1,624,668				1,094,464				1,150,194				(2,244,658	)			1,624,668
Total liabilities and stockholders’ equity		$	1,937,653			$	3,215,706			$	1,171,763			$	(3,052,008	)		$	3,273,114

		December 31, 2007
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent and Co-				(Issuer and Co-				Guarantor								Reources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Assets
Current assets		$	430,518			$	237,273			$	7,263			$	(434,695	)		$	240,359
Property and equipment			—				2,392,865				10				—				2,392,875
Investment in subsidiaries (equity method)			961,990				—				905,796				(1,867,786	)			—
Other assets			312,556				78,230				57,226				(310,169	)			137,843
Total assets		$	1,705,064			$	2,708,368			$	970,295			$	(2,612,650	)		$	2,771,077
Liabilities and Stockholders’ Equity
Current liabilities		$	—			$	691,062			$	8,266			$	(434,695	)		$	264,633
Long-term liabilities			300,686				1,111,510				39				(310,169	)			1,102,066
Stockholders’ equity			1,404,378				905,796				961,990				(1,867,786	)			1,404,378
Total liabilties and stockholders’ equity		$	1,705,064			$	2,708,368			$	970,295			$	(2,612,650	)		$	2,771,077

DENBURY RESOURCES INC.

     Condensed Consolidating Statements of Operations

		Three Months Ended June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent & Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	5,625			$	417,218			$	767			$	(5,625	)		$	417,985
Expenses			5,746				233,361				828				(5,625	)			234,310
Income (loss) before the following:			(121	)			183,857				(61	)			—				183,675
Equity in net earnings of subsidiaries			114,171				—				114,449				(228,620	)			—
Income before income taxes			114,050				183,857				114,388				(228,620	)			183,675
Income tax provision (benefit)			(3	)			69,408				217				—				69,622
Net income		$	114,053			$	114,449			$	114,171			$	(228,620	)		$	114,053

		Three Months Ended June 30, 2007
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent & Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	5,531			$	222,619			$	(109	)		$	(5,531	)		$	222,510
Expenses			5,646				119,244				674				(5,531	)			120,033
Income (loss) before the following:			(115	)			103,375				(783	)			—				102,477
Equity in net earnings of subsidiaries			62,676				—				63,372				(126,048	)			—
Income before income taxes			62,561				103,375				62,589				(126,048	)			102,477
Income tax provision (benefit)			(6	)			40,003				(87	)			—				39,910
Net income		$	62,567			$	63,372			$	62,676			$	(126,048	)		$	62,567

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Operations (continued)

		Six Months Ended June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent & Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	11,250			$	734,462			$	858			$	(11,250	)		$	735,320
Expenses			11,491				433,883				1,632				(11,250	)			435,756
Income (loss) before the following:			(241	)			300,579				(774	)			—				299,564
Equity in net earnings of subsidiaries			187,275				—				188,254				(375,529	)			—
Income before income taxes			187,034				300,579				187,480				(375,529	)			299,564
Income tax provision (benefit)			(21	)			112,325				205				—				112,509
Net income		$	187,055			$	188,254			$	187,275			$	(375,529	)		$	187,055

		Six Months Ended June 30, 2007
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent & Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Revenues		$	8,344			$	396,611			$	54			$	(8,344	)		$	396,665
Expenses			8,550				265,446				1,288				(8,344	)			266,940
Income (loss) before the following:			(206	)			131,165				(1,234	)			—				129,725
Equity in net earnings of subsidiaries			79,379				—				80,570				(159,949	)			—
Income before income taxes			79,173				131,165				79,336				(159,949	)			129,725
Income tax provision (benefit)			(10	)			50,595				(43	)			—				50,542
Net income		$	79,183			$	80,570			$	79,379			$	(159,949	)		$	79,183

DENBURY RESOURCES INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Condensed Consolidating Statements of Cash Flows

		Six Months Ended June 30, 2008
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent & Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Cash flow from operations		$	(10	)		$	370,325			$	14			$	—			$	370,329
Cash flow from investing activities			(23,757	)			(384,797	)			2,725				23,757				(382,072	)
Cash flow from financing activities			23,757				98,645				—				(23,757	)			98,645
Net increase (decrease) in cash			(10	)			84,173				2,739				—				86,902
Cash, beginning of period			34				58,343				1,730				—				60,107
Cash, end of period		$	24			$	142,516			$	4,469			$	—			$	147,009

		Six Months Ended June 30, 2007
		Denbury				Denbury
		Resources Inc.				Onshore, LLC				Other								Denbury
		(Parent & Co-				(Issuer and Co-				Guarantor								Resources Inc.
Amounts in thousands		Obligor)				Obligor)				Subsidiaries				Eliminations				Consolidated
Cash flow from operations		$	33			$	195,195			$	369			$	—			$	195,597
Cash flow from investing activities			(170,258	)			(421,019	)			—				170,258				(421,019	)
Cash flow from financing activities			170,258				204,126				—				(170,258	)			204,126
Net increase (decrease) in cash			33				(21,698	)			369				—				(21,296	)
Cash, beginning of period			1				52,225				1,647				—				53,873
Cash, end of period		$	34			$	30,527			$	2,016			$	—			$	32,577

DENBURY RESOURCES INC.

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

     You should read the following in conjunction with our financial statements contained herein and our Form 10-K for the year ended December 31, 2007, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K.

     We are a growing independent oil and gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest carbon dioxide (“CO₂”) reserves east of the Mississippi River used for tertiary oil recovery, and hold significant operating acreage in the Barnett Shale play near Fort Worth, Texas, onshore Louisiana, Alabama, and properties in Southeast Texas. Our primary goal is to increase the value of acquired properties through tertiary recovery operations, together with a combination of exploitation, drilling, and proven engineering extraction processes. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have four primary field offices located in Laurel, Mississippi; McComb, Mississippi; Jackson, Mississippi; and Cleburne, Texas.

Overview

     Operating results. During the second quarter of 2008 our production averaged 46,305 BOE/d, a 25% increase over second quarter 2007 production after adjusting for the sale of our Louisiana natural gas properties in December 2007 and February 2008, and a 4% increase over production levels in the first quarter of 2008 (also adjusted for the Louisiana property sale). These increases were primarily from increases in our tertiary oil and Barnett Shale production. Commodity prices continued to increase during the second quarter of 2008, resulting in a 72% increase in our average per BOE price received in the second quarter of 2007, and a 28% increase over first quarter of 2008 average per BOE price received. As a result of the rising prices during the first half of 2008, we recognized non-cash fair value losses on our oil and natural gas derivative contracts of $38.7 million in the first quarter of 2008 and $30.2 million in the second quarter, and also made cash payments of $8.0 million and $28.6 million on our derivative contract settlements in the first and second quarters of 2008, respectively. This compares to a $21.8 million non-cash fair value charge on our derivative contracts in the first half of 2007 and net cash receipts of $10.0 million during that same period.

     All of our expenses, other than interest expense, increased on both an absolute and per BOE basis during the second quarter of 2008, due to (i) higher overall industry costs, (ii) a higher percentage of operations related to tertiary operations (which have higher operating costs per BOE), and (iii) higher compensation expense resulting from additional employees and increased salaries, which we consider necessary in order to remain competitive in the industry. In addition, the sale of our Louisiana natural gas properties, which had lower operating costs per BOE, increased our operating cost per BOE by over $1.00, based on 2007 average costs. Interest expense decreased slightly in the 2008 periods as we capitalized more interest because of the significant expenditures made during 2007 and 2008 on unevaluated properties. The net result was net income of $114.1 million during the second quarter of 2008, a company quarterly record, as compared to $62.6 million of net income during the second quarter of 2007. On a six month basis, net income was $187.1 million during the first half of 2008 as compared to $79.2 million during the first half of 2007 as higher commodity prices and production in 2008 more than offset the higher expenses.

     We continue to have a high rate of inflation in our industry, particularly for certain items such as steel products. Likewise, the availability of goods and services is mixed, with improvements in some areas such as rig availability, but still long lead times for certain items, such as compressors used in our tertiary recycle facilities and construction services for pipelines. There is also significant competition for technical and experienced personnel and overall compensation inflation in our industry appears to be much higher than the national average. It is difficult to forecast price trends and supply, service or personnel availability, which if adverse, would significantly impact both operating costs and capital expenditures, as well as cause delays in achieving our anticipated production targets and development goals.

     Overview of tertiary operations. Since we acquired our first carbon dioxide tertiary flood in Mississippi in 1999, we have gradually increased our emphasis on these types of operations. We particularly like this play because of its risk profile, rate of return and lack of competition in our operating area. Generally, from East Texas to Florida, there are no known significant natural sources of carbon dioxide except our own, and these large volumes of CO₂ that we own drive the play. Please refer to the section entitled “CO₂ Operations” below and contained in Management’s Discussion and

DENBURY RESOURCES INC.

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

Analysis of Financial Condition and Results of Operations in our 2007 Form 10-K for further information regarding these operations.

     Oil production from our tertiary operations increased to an average of 18,661 BOE/d in the second quarter of 2008, a 36% increase over the second quarter 2007 tertiary production level of 13,683 BOE/d, and a 9% increase over the first quarter 2008 tertiary production level. As a result of our initial tertiary oil production from Tinsley Field (Phase III) in the second quarter of 2008, we recognized approximately 29.8 million barrels (“MMBbls”) of proved reserves at Tinsley Field, although we do not believe that these proved reserve quantities represent the total ultimate reserves we expect to recover from this field with tertiary operations. For a further discussion, see “Results of Operations — CO₂ Operations”.

     Genesis Transactions. On May 30, 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving our NEJD and Free State CO₂ Pipelines, which included a long-term transportation service arrangement for the Free State line and a 20-year financing lease for the NEJD system. We received from Genesis $225 million in cash and $25 million of Genesis common limited partnership units (1,199,041 units at an average price of $20.85 per unit). The Company has capitalized these transactions for accounting purposes and currently projects that it will initially pay Genesis approximately $30 million per annum under the financing lease and transportation services agreement (a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline payments fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State Pipeline dependant on the volumes of CO₂ transported therein.

     Change in Tax Accounting Method for Certain Tertiary Costs. The Company recently obtained approval from the Internal Revenue Service (“IRS”) to change its method of tax accounting for certain assets used in its tertiary oilfield recovery operations. Previously, the Company capitalized and depreciated these costs, but now it can deduct these costs once the assets are placed into service. As a result, the Company expects to receive tax refunds of approximately $6 million for tax years through 2007, and in the second quarter of 2008 has reduced its current income tax expense by approximately $19 million to adjust for the impact of this change through the first six months of 2008. The reduction in current income tax expense has been offset by a corresponding increase in deferred income tax expense of approximately the same amount. This change is not expected to have a significant impact on our overall tax rate; however, we expect that it will reduce the amount of cash taxes we will pay over the next several years.

     Our acceleration of tax deductions and resultant lower current cash income taxes will change the overall economics of certain financing-type transactions we have historically utilized, primarily equipment lease financing and certain transactions with Genesis (see paragraph below). For several years, we have entered into seven or ten year operating leases for portions of the tertiary facility equipment. Through June 30, 2008, we have leased approximately $104.5 million of such equipment and had anticipated leasing additional equipment during 2008. In order to fully take advantage of the change in tax accounting, we have discontinued this leasing program, which is estimated to increase our 2008 capital budget by approximately $78 million, with the offset being a reduction of future lease operating expenses.

     The economic impact of our acceleration of tax deductions will also likely lead us to eliminate certain types of future asset “drop-downs” to Genesis. Transactions which are not sales for tax purposes, such as the recent $175 million financing lease on the NEJD CO₂ Pipeline (see “Overview — Genesis Transactions” above) would not be affected provided that they meet other necessary tax structuring criteria. Those transactions which constitute a sale for tax purposes, such as the recent $75 million sale and associated long-term transportation service agreement entered into with Genesis on our Free State CO₂ Pipeline (see “Overview — Genesis Transactions” above), are likely to be discontinued.

     Sale of Louisiana Natural Gas Assets. We completed the remaining 30% of the sale of our Louisiana natural gas assets in February 2008 with additional proceeds received at that time of approximately $48.9 million, the prior 70% of which closed in December 2007. Production attributable to the sold properties averaged 302 BOE/d (approximately 81% natural gas) during the first quarter of 2008, representing the production prior to the closing date for the portion of the sale that closed in February. Production attributable to the sold properties averaged approximately 30.6 MMcfe/d (82% natural gas) during the fourth quarter of 2007, representing approximately 10% of our total fourth quarter production and approximately 4% of our total proved reserve quantities as of December 31, 2006.

DENBURY RESOURCES INC.

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

Capital Resources and Liquidity

     We have recently increased our current 2008 capital exploration and development budget by $100 million to approximately $1.0 billion, excluding any potential acquisitions, reflecting among other adjustments, the change in our operating lease program discussed above (see “Overview — Change in Tax Accounting Method for Certain Tertiary Costs”). The current 2008 program includes an estimated $190 million to acquire pipe and right-of-ways for our proposed CO₂ pipeline from Louisiana to Texas (the “Green Pipeline”) and another $90 million for the segment of the Delta CO₂ Pipeline from Tinsley to Delhi Fields. We expect to spend an additional $500 million constructing the Green Pipeline during 2009, making our current anticipated total cost for that line approximately $700 million. Currently, over 75% of our 2008 budget is expected to be spent on tertiary related operations, approximately 15% in the Barnett Shale area, and the balance in other areas.

     Last fall when we set our initial 2008 capital budget, it was forecasted to be significantly in excess of our projected cash flow from operations. However, with the significant increases in commodity prices since that time and based on oil and natural gas commodity prices as of late July 2008, we currently project that even with our increased capital budget, our 2008 cash flow should be sufficient to fund almost all of our current 2008 capital budget. With the recent influx of cash related to the two pipeline transactions with Genesis (see “Overview — Genesis Transactions”), we currently have no bank debt and as of July 31, 2008, had approximately $150 million of excess cash on hand. While the recent change in our tax accounting (which will accelerate our tax deductions and result in lower current cash income taxes) has changed the economics of certain financing methods (see “Overview — Change in Tax Accounting Method for Certain Tertiary Costs”) and will likely lead us to purchase rather than lease various equipment, thus requiring more capital, we do not anticipate requiring more than our bank credit line for our capital needs for the foreseeable future, except for the potential funding of acquisitions.

     As part of our semi-annual bank review, our bank borrowing base was increased as of April 1, 2008 from $500 million to $1.0 billion as a result of our continued growth, along with the higher commodity prices. With regard to our bank credit facility, the borrowing base represents the amount that can be borrowed from a credit standpoint based on our assets, as confirmed by the banks, while our $350 million commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. The banks have the option to participate in any borrowing request by us in excess of the commitment amount ($350 million), up to the borrowing base limit ($1.0 billion), although the banks are not obligated to fund any amount in excess of the commitment amount. At July 31, 2008, we had outstanding $525 million (principal amount) of 7.5% subordinated notes and no bank debt.

     We monitor our capital expenditures on a regular basis, adjusting them up or down depending on commodity prices and the resultant cash flow. Therefore, during the last few years as commodity prices have increased, we have increased our capital budget throughout the year. As a result of the recent cost inflation in our industry, many of our recent budget increases have related to escalating costs rather than additional projects. If costs do rise or we spend more than our estimated or forecasted amounts, we will either have to increase our capital budget or consider the elimination of a portion of our planned projects.

     We also continue to pursue acquisitions of mature oil fields that we believe have potential as future tertiary flood candidates. These possible acquisitions are difficult to forecast and the purchase price can vary widely depending on the levels of existing production and conventional proved reserves and commodity prices. Because of the current high commodity price environment, the cost of acquiring fields whose primary and secondary reserves are largely depleted and only have minor amounts of current production can still be significant. Any acquisitions would be funded, at least temporarily, with bank or other debt, although if significant, the acquisition would likely be ultimately funded with more permanent capital such as subordinated debt and/or additional equity or the potential sale of other non-core assets.

DENBURY RESOURCES INC.

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

Sources and Uses of Capital Resources

		Six Months Ended
		June 30,
Amounts in thousands		2008				2007
Capital expenditures
Oil and gas exploration and development
Drilling		$	129,187			$	159,448
Geological, geophysical and acreage			9,475				10,558
Facilities			79,085				56,259
Recompletions			71,539				64,988
Capitalized interest			9,717				8,056
Total oil and gas exploration and development expenditures			299,003				299,309
Oil and gas property acquisitions			2,357				46,660
Total oil and natural gas capital expenditures			301,360				345,969
CO2 capital expenditures, including capitalized interest			108,850				68,427
Total		$	410,210			$	414,396

     Our first half 2008 capital expenditures were funded with $370.3 million of cash flow from operations, $225 million from the drop-down of CO₂ pipelines to Genesis, and $48.9 million of proceeds from the second closing on our Louisiana property sale. The excess cash generated from these sources was used to repay our outstanding bank debt of $150 million, while the remainder of this excess increased our cash balances.

     Our 2007 capital expenditures were funded with $195.6 million of cash flow from operations, $150.0 million from our issuance of subordinated debt in April of that year, $36.0 million of net bank borrowings, and the balance funded with working capital.

Off-Balance Sheet Arrangements

Commitments and Obligations

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

     During the second quarter of 2008, we entered into transactions with Genesis relating to two of our CO₂ pipelines (see “Overview — Genesis Transactions” above). As a result of these two transactions, we currently project that we will initially pay Genesis approximately $30 million per annum under the financing lease and transportation services agreement (a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline payments fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State Pipeline dependant on the volumes of CO₂ transported therein, with a minimum annual payment thereon of $1.2 million.

     During the second quarter of 2008, we entered into a long-term commitment to purchase manufactured CO₂ from a proposed gasification plant proposed by Cash Creek Generation LLC and cancelled a contract we had executed for a proposed facility in Beaumont which we do not expect to be constructed. The plant proposed by Cash Creek is not only conditioned on that plant being built, but also upon Denbury contracting additional volumes in the general area which aggregate 600 MMcf/d in order to justify the cost of a CO₂ pipeline to this area. Both the new contract and the cancelled contract called for production of approximately 200 MMcf/d of CO₂ and the delivered price of CO₂ in both contracts is similar. If this most recently proposed plant and the other two plants are built, the aggregate purchase obligation for CO₂ from our contracted potential synthetic sources could be up to $200 million per year, assuming a $130 per barrel oil price and comparable compression levels, before any potential savings from our share of any carbon emissions credits enacted. All of the contracts have price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on any of these plants, and their construction is contingent on the satisfactory resolution of various issues, including

DENBURY RESOURCES INC.

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

financing. While it is possible that not every plant currently under contract will be built, there are several other plants under consideration that may be built and with whom we are having ongoing negotiations. These amounts were not included in the commitment table included in our Form 10-K as these payments are contingent on the plants being built.

     Neither the amounts nor the terms of any other commitments or contingent obligations have changed significantly from the year-end 2007 amounts reflected in our Form 10-K filed in February 2008, except for the transactions with Genesis noted above. Please refer to the “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Off-Balance Sheet Arrangements-Commitments and Obligations” contained in our 2007 Form 10-K for further information regarding our commitments and obligations.

Results of Operations

CO₂ Operations

     Our focus on CO₂ operations is becoming an ever-increasing part of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO₂, and we have outlined certain of this potential in our 2007 annual report and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the section entitled “CO₂ Operations” contained in our 2007 Form 10-K for further information regarding these matters.

     During 2008 we plan to drill five additional CO₂ source wells to further increase our production capacity and reserves. We estimate that we are currently capable of producing between 750 MMcf/d and 850 MMcf/d of CO_2. During the second quarter of 2008 our CO₂ production averaged 596 MMcf/d, as compared to an average of approximately 477 MMcf/d during the second quarter of 2007. We used 86% of this production, or 510 MMcf/d, in our tertiary operations during the second quarter of 2008, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.

     Oil production from our tertiary operations increased to an average of 18,661 BOE/d in the second quarter of 2008, a 36% increase over the second quarter 2007 tertiary production level of 13,683 BOE/d and a 9% increase over the first quarter 2008 tertiary production level. We saw our initial production from Tinsley Field (Phase III) in the second quarter of 2008, averaging 675 Bbls/d during the quarter. As a result of this production response to our CO₂ injections, we recognized approximately 29.8 MMBbls of proved reserves at Tinsley Field, although we do not believe that these proved reserve quantities represent the total ultimate reserves we expect to recover from this field with tertiary operations. The majority of the remaining production increase came from our Phase II operations in eastern Mississippi (Soso, Eucutta and Martinville Fields) which contributed 3,304 BOE/d (approximately two-thirds) to the increase over the prior year’s second quarter production, with the balance of the increase coming from our Phase I fields, except Little Creek Field which is on a gradual decline.

DENBURY RESOURCES INC.

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

		Average Daily Production (BOE/d)
		First				Second				Third				Fourth					First				Second
		Quarter				Quarter				Quarter				Quarter					Quarter				Quarter
Tertiary Oil Field		2007				2007				2007				2007					2008				2008
Phase I:
Brookhaven			1,422				1,794				2,452				2,507					2,638				2,714
Little Creek area			2,117				1,974				2,011				1,957					1,807				1,661
Mallalieu area			5,470				5,802				5,823				6,304					6,099				6,260
McComb area			1,811				1,884				1,853				2,096					1,632				1,818
Phase II:
Martinville			320				521				1,101				883					793				715
Eucutta			614				1,338				2,035				2,572					2,699				2,933
Soso			25				370				826				1,109					1,488				1,885
Phase III:
Tinsley			—				—				—				—					—				675
Total tertiary oil production			11,779				13,683				16,101				17,428					17,156				18,661